Ranging methods for developing wellbores in subsurface formations

ABSTRACT

A method for forming two or more wellbores in a subsurface formation includes forming a first wellbore in the formation. A second wellbore is directionally drilled in a selected relationship relative to the first wellbore. At least one magnetic field is provided in the second wellbore using one or more magnets in the second wellbore located on a drilling string used to drill the second wellbore. At least one magnetic field is sensed in the first wellbore using at least two sensors in the first wellbore as the magnetic field passes by the at least two sensors while the second wellbore is being drilled. A position of the second wellbore is continuously assessed relative to the first wellbore using the sensed magnetic field. The direction of drilling of the second wellbore is adjusted so that the second wellbore remains in the selected relationship relative to the first wellbore.

PRIORITY CLAIM

This patent application claims priority to U.S. Provisional Patent No.60/999,839 entitled “SYSTEMS AND PROCESSES FOR USE IN TREATINGSUBSURFACE FORMATIONS” to Vinegar et al. filed on Oct. 19, 2007 and toU.S. Provisional Patent No. 61/046,329 entitled “METHODS, SYSTEMS ANDPROCESSES FOR USE IN TREATING SUBSURFACE FORMATIONS” to Vinegar et al.filed on Apr. 18, 2008.

RELATED PATENTS

This patent application incorporates by reference in its entirety eachof U.S. Pat. Nos. 6,688,387 to Wellington et al.; 6,991,036 toSumnu-Dindoruk et al.; 6,698,515 to Karanikas et al.; 6,880,633 toWellington et al.; 6,782,947 to de Rouffignac et al; 6,991,045 toVinegar et al.; 7,073,578 to Vinegar et al.; 7,121,342 to Vinegar et al;and 7,320,364 to Fairbanks. This patent application incorporates byreference in its entirety each of U.S. Patent Application Publication2007-0133960 to Vinegar et al., U.S. Patent Application Publication2007-0221377 to Vinegar et al., U.S. Patent Application Publication2008-0017380 to Vinegar et al, and U.S. Patent Application Publication2008-0217015 to Vinegar et al. This patent application incorporates byreference in its entirety U.S. patent application Ser. No. 12/106,035 toVinegar et al.

GOVERNMENT INTEREST

The Government has certain rights in the invention pursuant to AgreementNos. SD 10634 and NFE 062050824 between Sandia National Laboratories(operating under Agreement DE-AC04-94AL85000Sa for the U.S. Departmentof Energy) and Shell Exploration and Production Company.

BACKGROUND

1. Field of the Invention

The present invention relates generally to methods and systems forproduction of hydrocarbons, hydrogen, and/or other products from varioussubsurface formations such as hydrocarbon containing formations.

2. Description of Related Art

Hydrocarbons obtained from subterranean formations are often used asenergy resources, as feedstocks, and as consumer products. Concerns overdepletion of available hydrocarbon resources and concerns over decliningoverall quality of produced hydrocarbons have led to development ofprocesses for more efficient recovery, processing and/or use ofavailable hydrocarbon resources. In situ processes may be used to removehydrocarbon materials from subterranean formations. Chemical and/orphysical properties of hydrocarbon material in a subterranean formationmay need to be changed to allow hydrocarbon material to be more easilyremoved from the subterranean formation. The chemical and physicalchanges may include in situ reactions that produce removable fluids,composition changes, solubility changes, density changes, phase changes,and/or viscosity changes of the hydrocarbon material in the formation. Afluid may be, but is not limited to, a gas, a liquid, an emulsion, aslurry, and/or a stream of solid particles that has flow characteristicssimilar to liquid flow.

During some in situ processes, wax may be used to reduce vapors and/orto encapsulate contaminants in the ground. Wax may be used duringremediation of wastes to encapsulate contaminated material. U.S. Pat.Nos. 7,114,880 to Carter, and 5,879,110 to Carter, each of which isincorporated herein by reference, describe methods for treatment ofcontaminants using wax during the remediation procedures.

In some embodiments, a casing or other pipe system may be placed orformed in a wellbore. U.S. Pat. No. 4,572,299 issued to Van Egmond etal., which is incorporated by reference as if fully set forth herein,describes spooling an electric heater into a well. In some embodiments,components of a piping system may be welded together. Quality of formedwells may be monitored by various techniques. In some embodiments,quality of welds may be inspected by a hybrid electromagnetic acoustictransmission technique known as EMAT. EMAT is described in U.S. Pat.Nos. 5,652,389 to Schaps et al.; 5,760,307 to Latimer et al.; 5,777,229to Geier et al.; and 6,155,117 to Stevens et al., each of which isincorporated by reference as if fully set forth herein.

In some embodiments, an expandable tubular may be used in a wellbore.Expandable tubulars are described in U.S. Pat. Nos. 5,366,012 toLohbeck, and 6,354,373 to Vercaemer et al., each of which isincorporated by reference as if fully set forth herein.

Heaters may be placed in wellbores to heat a formation during an in situprocess. Examples of in situ processes utilizing downhole heaters areillustrated in U.S. Pat. Nos. 2,634,961 to Ljungstrom; 2,732,195 toLjungstrom; 2,780,450 to Ljungstrom; 2,789,805 to Ljungstrom; 2,923,535to Ljungstrom; and 4,886,118 to Van Meurs et al.; each of which isincorporated by reference as if fully set forth herein.

Application of heat to oil shale formations is described in U.S. Pat.Nos. 2,923,535 to Ljungstrom and 4,886,118 to Van Meurs et al. Heat maybe applied to the oil shale formation to pyrolyze kerogen in the oilshale formation. The heat may also fracture the formation to increasepermeability of the formation. The increased permeability may allowformation fluid to travel to a production well where the fluid isremoved from the oil shale formation. In some processes disclosed byLjungstrom, for example, an oxygen containing gaseous medium isintroduced to a permeable stratum, preferably while still hot from apreheating step, to initiate combustion.

A heat source may be used to heat a subterranean formation. Electricheaters may be used to heat the subterranean formation by radiationand/or conduction. An electric heater may resistively heat an element.U.S. Pat. No. 2,548,360 to Germain, which is incorporated by referenceas if fully set forth herein, describes an electric heating elementplaced in a viscous oil in a wellbore. The heater element heats andthins the oil to allow the oil to be pumped from the wellbore. U.S. Pat.No. 4,716,960 to Eastlund et al., which is incorporated by reference asif fully set forth herein, describes electrically heating tubing of apetroleum well by passing a relatively low voltage current through thetubing to prevent formation of solids. U.S. Pat. No. 5,065,818 to VanEgmond, which is incorporated by reference as if fully set forth herein,describes an electric heating element that is cemented into a wellborehole without a casing surrounding the heating element.

U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporated byreference as if fully set forth herein, describes an electric heatingelement that is positioned in a casing. The heating element generatesradiant energy that heats the casing. A granular solid fill material maybe placed between the casing and the formation. The casing mayconductively heat the fill material, which in turn conductively heatsthe formation.

U.S. Pat. No. 4,570,715 to Van Meurs et al., which is incorporated byreference as if fully set forth herein, describes an electric heatingelement. The heating element has an electrically conductive core, asurrounding layer of insulating material, and a surrounding metallicsheath. The conductive core may have a relatively low resistance at hightemperatures. The insulating material may have electrical resistance,compressive strength, and heat conductivity properties that arerelatively high at high temperatures. The insulating layer may inhibitarcing from the core to the metallic sheath. The metallic sheath mayhave tensile strength and creep resistance properties that arerelatively high at high temperatures.

U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated byreference as if fully set forth herein, describes an electrical heatingelement having a copper-nickel alloy core.

Obtaining permeability in an oil shale formation between injection andproduction wells tends to be difficult because oil shale is oftensubstantially impermeable. Many methods have attempted to link injectionand production wells. These methods include: hydraulic fracturing suchas methods investigated by Dow Chemical and Laramie Energy ResearchCenter; electrical fracturing by methods investigated by Laramie EnergyResearch Center; acid leaching of limestone cavities by methodsinvestigated by Dow Chemical; steam injection into permeable nahcolitezones to dissolve the nahcolite by methods investigated by Shell Oil andEquity Oil; fracturing with chemical explosives by methods investigatedby Talley Energy Systems; fracturing with nuclear explosives by methodsinvestigated by Project Bronco; and combinations of these methods. Manyof these methods, however, have relatively high operating costs and lacksufficient injection capacity.

Large deposits of heavy hydrocarbons (heavy oil and/or tar) contained inrelatively permeable formations (for example in tar sands) are found inNorth America, South America, Africa, and Asia. Tar can be surface-minedand upgraded to lighter hydrocarbons such as crude oil, naphtha,kerosene, and/or gas oil. Surface milling processes may further separatethe bitumen from sand. The separated bitumen may be converted to lighthydrocarbons using conventional refinery methods. Mining and upgradingtar sand is usually substantially more expensive than producing lighterhydrocarbons from conventional oil reservoirs.

In situ production of hydrocarbons from tar sand may be accomplished byheating and/or injecting a gas into the formation. U.S. Pat. Nos.5,211,230 to Ostapovich et al. and 5,339,897 to Leaute, which areincorporated by reference as if fully set forth herein, describe ahorizontal production well located in an oil-bearing reservoir. Avertical conduit may be used to inject an oxidant gas into the reservoirfor in situ combustion.

U.S. Pat. No. 2,780,450 to Ljungstrom describes heating bituminousgeological formations in situ to convert or crack a liquid tar-likesubstance into oils and gases.

U.S. Pat. No. 4,597,441 to Ware et al., which is incorporated byreference as if fully set forth herein, describes contacting oil, heat,and hydrogen simultaneously in a reservoir. Hydrogenation may enhancerecovery of oil from the reservoir.

U.S. Pat. Nos. 5,046,559 to Glandt and 5,060,726 to Glandt et al., whichare incorporated by reference as if fully set forth herein, describepreheating a portion of a tar sand formation between an injector welland a producer well. Steam may be injected from the injector well intothe formation to produce hydrocarbons at the producer well.

As outlined above, there has been a significant amount of effort todevelop methods and systems to economically produce hydrocarbons,hydrogen, and/or other products from hydrocarbon containing formations.At present, however, there are still many hydrocarbon containingformations from which hydrocarbons, hydrogen, and/or other productscannot be economically produced. Thus, there is still a need forimproved methods and systems for production of hydrocarbons, hydrogen,and/or other products from various hydrocarbon containing formations.

SUMMARY

Embodiments described herein generally relate to systems, methods, andheaters for treating a subsurface formation. Embodiments describedherein also generally relate to heaters that have novel componentstherein. Such heaters can be obtained by using the systems and methodsdescribed herein.

In certain embodiments, the invention provides one or more systems,methods, and/or heaters. In some embodiments, the systems, methods,and/or heaters are used for treating a subsurface formation.

In certain embodiments, a method for forming two or more wellbores in asubsurface formation includes forming a first wellbore in the formation;directionally drilling a second wellbore in a selected relationshiprelative to the first wellbore; providing at least one magnetic field inthe second wellbore using one or more magnets in the second wellborelocated on a drilling string used to drill the second wellbore; sensingat least one magnetic field in the first wellbore using at least twosensors in the first wellbore as the magnetic field passes by the atleast two sensors while the second wellbore is being drilled;continuously assessing a position of the second wellbore relative to thefirst wellbore using the sensed magnetic field; and adjusting thedirection of drilling of the second wellbore so that the second wellboreremains in the selected relationship relative to the first wellbore.

In certain embodiments, a method for forming two or more wellbores in asubsurface formation includes forming at least a first wellbore in theformation; providing a current path and voltage signal to the firstwellbore; directionally drilling a second wellbore in a selectedrelationship relative to the first wellbore; continuously sensing thevoltage signal in the second wellbore; continuously assessing a positionof the second wellbore relative to the first wellbore using the sensedvoltage signal; and adjusting the direction of drilling of the secondwellbore so that the second wellbore remains in the selectedrelationship relative to the first wellbore.

In certain embodiments, a method for forming two or more wellbores in asubsurface formation includes forming a first wellbore in the formation;directionally drilling a second wellbore in a selected relationshiprelative to the first wellbore; providing an electromagnetic wave in thesecond wellbore; continuously sensing the electromagnetic wave in thefirst wellbore using at least one electromagnetic antenna; continuouslyassessing a position of the second wellbore relative to the firstwellbore using the sensed electromagnetic wave; and adjusting thedirection of drilling of the second wellbore so that the second wellboreremains in the selected relationship relative to the first wellbore.

In certain embodiments, a method for forming two or more wellbores in asubsurface formation includes forming a first wellbore in the formation;directionally drilling a second wellbore in a selected relationshiprelative to the first wellbore; transmitting a first electromagneticwave from a first transceiver in the first wellbore and sensing thefirst electromagnetic wave using a second transceiver in the secondwellbore; transmitting a second electromagnetic wave from the secondtransceiver in the second wellbore and sensing the secondelectromagnetic wave using the first transceiver in the first wellbore;continuously assessing a position of the second wellbore relative to thefirst wellbore using the sensed first electromagnetic wave and thesensed second electromagnetic wave; and adjusting the direction ofdrilling of the second wellbore so that the second wellbore remains inthe selected relationship relative to the first wellbore.

In certain embodiments, a method for forming two or more wellbores in asubsurface formation includes forming a plurality of first wellbores inthe formation; providing a plurality of electromagnetic waves in thefirst wellbores; directionally drilling one or more second wellbores ina selected relationship relative to the first wellbores; continuouslysensing the electromagnetic waves in the first wellbores using at leastone electromagnetic antenna in the second wellbores; continuouslyassessing a position of the second wellbores relative to the firstwellbores using the sensed electromagnetic waves; and adjusting thedirection of drilling of at least one of the second wellbores so thatthe second wellbore remains in the selected relationship relative to thefirst wellbores.

In certain embodiments, a method for forming two or more wellbores in asubsurface formation includes forming a first wellbore in the formation;assessing a position of the first wellbore; drilling a second wellborein a selected relationship relative to the first wellbore; continuouslyassessing a position of the second wellbore relative to the firstwellbore; adjusting the direction of drilling of the second wellbore sothat the second wellbore remains in the selected relationship relativeto the first wellbore; drilling one or more additional wellbores in aselected relationship to the second wellbore; continuously assessing aposition of at least one of the additional wellbores relative to thefirst wellbore and/or the second wellbore; and adjusting the directionof drilling of the at least one of the additional wellbores so that theat least one of the additional wellbores remains in the selectedrelationship relative to the second wellbore.

In certain embodiments, a method for forming two or more wellbores in asubsurface formation includes forming a first wellbore in the formation;directionally drilling a second wellbore in a selected relationshiprelative to the first wellbore; providing an electromagnetic field inthe first wellbore using one or more magnets; continuously sensing theelectromagnetic field in the first wellbore using at least oneelectromagnetic field sensor positioned in the second wellbore;continuously assessing a position of the second wellbore relative to thefirst wellbore using the sensed electromagnetic field; and adjusting thedirection of drilling of the second wellbore so that the second wellboreremains in the selected relationship relative to the first wellbore.

In certain embodiments, a method for forming two or more wellbores in asubsurface formation includes forming a first wellbore in the formation;directionally drilling a second wellbore in a selected relationshiprelative to the first wellbore; providing an electromagnetic field inthe second wellbore using one or more magnets; continuously sensing theelectromagnetic field in the second wellbore using at least oneelectromagnetic field sensor positioned in the first wellbore;continuously assessing a position of the second wellbore relative to thefirst wellbore using the sensed electromagnetic field; and adjusting thedirection of drilling of the second wellbore so that the second wellboreremains in the selected relationship relative to the first wellbore.

In further embodiments, features from specific embodiments may becombined with features from other embodiments. For example, featuresfrom one embodiment may be combined with features from any of the otherembodiments.

In further embodiments, treating a subsurface formation is performedusing any of the methods, systems, or heaters described herein.

In further embodiments, additional features may be added to the specificembodiments described herein.

BRIEF DESCRIPTION OF THE DRAWINGS

Advantages of the present invention may become apparent to those skilledin the art with the benefit of the following detailed description andupon reference to the accompanying drawings in which:

FIG. 1 shows a schematic view of an embodiment of a portion of an insitu heat treatment system for treating a hydrocarbon containingformation.

FIG. 2 depicts a schematic representation of an embodiment of a systemfor treating in situ heat treatment process gas.

FIG. 3 depicts a schematic representation of an embodiment of a systemfor treating in situ heat treatment process gas.

FIG. 4 depicts a schematic representation of an embodiment of a systemfor treating in situ heat treatment process gas.

FIG. 5 depicts a schematic representation of an embodiment of a systemfor treating in situ heat treatment process gas.

FIG. 6 depicts a schematic representation of an embodiment of a systemfor treating in situ heat treatment process gas.

FIG. 7 depicts a schematic representation of an embodiment of a systemfor treating the mixture produced from an in situ heat treatmentprocess.

FIG. 8 depicts a schematic representation of an embodiment of a systemfor treating a liquid stream produced from an in situ heat treatmentprocess.

FIG. 9 depicts a schematic representation of an embodiment of a systemfor forming and transporting tubing to a treatment area.

FIG. 10 depicts an embodiment of a drilling string with dual motors on abottom hole assembly.

FIG. 11 depicts time versus rpm (revolutions per minute) for aconventional steerable motor bottom hole assembly during a drill bitdirection change.

FIG. 12 depicts time versus rpm for a dual motor bottom hole assemblyduring a drill bit direction change.

FIG. 13 depicts an embodiment of a drilling string with a non-rotatingsensor.

FIG. 14 depicts an embodiment for assessing a position of a firstwellbore relative to a second wellbore using multiple magnets.

FIG. 15 depicts an embodiment for assessing a position of a firstwellbore relative to a second wellbore using a continuous pulsed signal.

FIG. 16 depicts an embodiment for assessing a position of a firstwellbore relative to a second wellbore using a radio ranging signal.

FIG. 17 depicts an embodiment for assessing a position of a plurality offirst wellbores relative to a plurality of second wellbores using radioranging signals.

FIG. 18 depicts a top view representation of an embodiment for forming aplurality of wellbores in a formation.

FIGS. 19 and 20 depict an embodiment for assessing a position of a firstwellbore relative to a second wellbore using a heater assembly as acurrent conductor.

FIGS. 21 and 22 depict an embodiment for assessing a position of a firstwellbore relative to a second wellbore using two heater assemblies ascurrent conductors.

FIG. 23 depicts an embodiment of an umbilical positioning control systememploying a magnetic gradiometer system and wellbore to wellborewireless telemetry system.

FIG. 24 depicts an embodiment of an umbilical positioning control systememploying a magnetic gradiometer system in an existing wellbore.

FIG. 25 depicts an embodiment of an umbilical positioning control systememploying a combination of systems being used in a first stage ofdeployment.

FIG. 26 depicts an embodiment of an umbilical positioning control systememploying a combination of systems being used in a second stage ofdeployment.

FIG. 27 depicts two examples of the relationship between power receivedand distance based upon two different formations with differentresistivities.

FIG. 28A depicts an embodiment of a drilling string including cuttingstructures positioned along the drilling string.

FIG. 28B depicts an embodiment of a drilling string including cuttingstructures positioned along the drilling string.

FIG. 28C depicts an embodiment of a drilling string including cuttingstructures positioned along the drilling string.

FIG. 29 depicts an embodiment of a drill bit including upward cuttingstructures.

FIG. 30 depicts an embodiment of a tubular including cutting structurespositioned in a wellbore.

FIG. 31 depicts a cross-sectional representation of fluid flow in thedrilling string of a wellbore with no control of vaporization of thefluid.

FIG. 32 depicts a partial cross-sectional representation of a system fordrilling with controlled vaporization of drilling fluid to cool thedrilling bit.

FIG. 33 depicts a partial cross-sectional representation of a system forcooling a downhole region that utilizes triple walled drilling stringused and cooling fluid.

FIG. 34 depicts a partial cross-sectional representation of a reversecirculation flow scheme that uses cooling fluid, wherein the coolingfluid returns with the drilling fluid and cuttings.

FIG. 35 depicts a schematic of a rack and pinion drilling system.

FIGS. 36A through 36D depict schematics of an embodiment for acontinuous drilling sequence.

FIG. 37 depicts a schematic of an embodiment of circulating sleeves.

FIG. 38 depicts schematics of an embodiment of a circulating sleeve withvalves.

FIG. 39 depicts an embodiment of a bottom hole assembly for use withparticle jet drilling.

FIG. 40 depicts a rotating jet head with multiple nozzles for use duringparticle jet drilling.

FIG. 41 depicts a rotating jet head with a single nozzle for use duringparticle jet drilling.

FIG. 42 depicts a non-rotating jet head for use during particle jetdrilling.

FIG. 43 depicts a bottom hole assembly that uses an electric orienter tochange the direction of wellbore formation.

FIG. 44 depicts a bottom hole assembly that uses directional jets tochange the direction of wellbore formation.

FIG. 45 depicts a bottom hole assembly the uses a tractor system tochange the direction of wellbore formation.

FIG. 46 depicts a perspective representation of a robot used to move thebottom hole assembly in a wellbore.

FIG. 47 depicts a representation of the robot positioned against thebottom hole assembly.

FIG. 48 depicts a schematic representation of a first group of barrierwells used to form a first barrier and a second group of barrier wellsused to form a second barrier.

FIG. 49 depicts an embodiment of a freeze well for a circulated liquidrefrigeration system, wherein a cutaway view of the freeze well isrepresented below ground surface.

FIG. 50 depicts a representation of a portion of a freeze wellembodiment.

FIG. 51 depicts an embodiment of a wellbore for introducing wax into aformation to form a wax barrier.

FIG. 52A depicts a representation of a wellbore drilled to anintermediate depth in a formation.

FIG. 52B depicts a representation of the wellbore drilled to the finaldepth in the formation.

FIGS. 53, 54, and 55 depict cross-sectional representations of anembodiment of a temperature limited heater with an outer conductorhaving a ferromagnetic section and a non-ferromagnetic section.

FIGS. 56, 57, 58, and 59 depict cross-sectional representations of anembodiment of a temperature limited heater with an outer conductorhaving a ferromagnetic section and a non-ferromagnetic section placedinside a sheath.

FIGS. 60A and 60B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 61A and 61B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 62A and 62B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 63A and 63B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIGS. 64A and 64B depict cross-sectional representations of anembodiment of a temperature limited heater.

FIG. 65 depicts a cross-sectional representation of an embodiment of acomposite conductor with a support member.

FIG. 66 depicts a cross-sectional representation of an embodiment of acomposite conductor with a support member separating the conductors.

FIG. 67 depicts a cross-sectional representation of an embodiment of acomposite conductor surrounding a support member.

FIG. 68 depicts a cross-sectional representation of an embodiment of acomposite conductor surrounding a conduit support member.

FIG. 69 depicts a cross-sectional representation of an embodiment of aconductor-in-conduit heat source.

FIG. 70 depicts a cross-sectional representation of an embodiment of aremovable conductor-in-conduit heat source.

FIG. 71 depicts a cross-sectional representation of an embodiment of atemperature limited heater in which the support member provides amajority of the heat output below the Curie temperature of theferromagnetic conductor.

FIGS. 72 and 73 depict cross-sectional representations of embodiments oftemperature limited heaters in which the jacket provides a majority ofthe heat output below the Curie temperature of the ferromagneticconductor.

FIGS. 74A and 74B depict cross-sectional representations of anembodiment of a temperature limited heater component used in aninsulated conductor heater.

FIG. 75 depicts a top view representation of three insulated conductorsin a conduit.

FIG. 76 depicts an embodiment of three-phase wye transformer coupled toa plurality of heaters.

FIG. 77 depicts a side view representation of an end section of threeinsulated conductors in a conduit.

FIG. 78 depicts an embodiment of a heater with three insulated cores ina conduit.

FIG. 79 depicts an embodiment of a heater with three insulatedconductors and an insulated return conductor in a conduit.

FIG. 80 depicts a cross-sectional representation of an embodiment ofthree insulated conductors banded together.

FIG. 81 depicts a cross-sectional representation of an embodiment ofthree insulated conductors banded together with a support member betweenthe insulated conductors.

FIG. 82 depicts outer tubing partially unspooled from a coiled tubingrig.

FIG. 83 depicts a heater being pushed into outer tubing partiallyunspooled from a coiled tubing rig.

FIG. 84 depicts a heater being fully inserted into outer tubing with adrilling guide coupled to the end of the heater.

FIG. 85 depicts a heater, outer tubing, and drilling guide spooled ontoa coiled tubing rig.

FIG. 86 depicts a coiled tubing rig being used to install a heater andouter tubing into an opening using a drilling guide.

FIG. 87 depicts a heater and outer tubing installed in an opening.

FIG. 88 depicts outer tubing being removed from an opening while leavinga heater installed in the opening.

FIG. 89 depicts outer tubing used to provide a packing material into anopening.

FIG. 90 depicts outer tubing being spooled onto a coiled tubing rigafter packing material is provided into an opening.

FIG. 91 depicts outer tubing spooled onto a coiled tubing rig with aheater installed in an opening.

FIG. 92 depicts a heater installed in an opening with a wellhead.

FIG. 93 depicts an embodiment of an insulated conductor in a conduitwith liquid between the insulated conductor and the conduit.

FIG. 94 depicts an embodiment of an insulated conductor heater in aconduit with a conductive liquid between the insulated conductor and theconduit.

FIG. 95 depicts an embodiment of an insulated conductor in a conduitwith liquid between the insulated conductor and the conduit, where aportion of the conduit and the insulated conductor are orientedhorizontally in the formation.

FIG. 96 depicts a cross-sectional representation of a ribbed conduit.

FIG. 97 depicts a perspective representation of a portion of a ribbedconduit.

FIG. 98 depicts an embodiment of a portion of an insulated conductor ina bottom portion of an open wellbore with a liquid between the insulatedconductor and the formation.

FIG. 99 depicts a schematic cross-sectional representation of a portionof a formation with heat pipes positioned adjacent to a substantiallyhorizontal portion of a heat source.

FIG. 100 depicts a perspective cut-out representation of a portion of aheat pipe embodiment with the heat pipe located radially around anoxidizer assembly.

FIG. 101 depicts a cross-sectional representation of an angled heat pipeembodiment with an oxidizer assembly located near a lowermost portion ofthe heat pipe.

FIG. 102 depicts a perspective cut-out representation of a portion of aheat pipe embodiment with an oxidizer located at the bottom of the heatpipe.

FIG. 103 depicts a cross-sectional representation of an angled heat pipeembodiment with an oxidizer located at the bottom of the heat pipe.

FIG. 104 depicts a perspective cut-out representation of a portion of aheat pipe embodiment with an oxidizer that produces a flame zoneadjacent to liquid heat transfer fluid in the bottom of the heat pipe.

FIG. 105 depicts a perspective cut-out representation of a portion of aheat pipe embodiment with a tapered bottom that accommodates multipleoxidizers.

FIG. 106 depicts a cross-sectional representation of a heat pipeembodiment that is angled within the formation.

FIG. 107 depicts an embodiment of a three-phase temperature limitedheater with a portion shown in cross section.

FIG. 108 depicts an embodiment of temperature limited heaters coupledtogether in a three-phase configuration.

FIG. 109 depicts an embodiment of three heaters coupled in a three-phaseconfiguration.

FIG. 110 depicts a cross-sectional representation of an embodiment of acentralizer on a heater.

FIG. 111 depicts a cross-sectional representation of an embodiment of acentralizer on a heater.

FIG. 112 depicts a side view representation of an embodiment of asubstantially u-shaped three-phase heater in a formation.

FIG. 113 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a formation.

FIG. 114 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a formation withproduction wells.

FIG. 115 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a hexagonal pattern.

FIG. 116 depicts a top view representation of an embodiment of a hexagonfrom FIG. 115.

FIG. 117 depicts an embodiment of triads of heaters coupled to ahorizontal bus bar.

FIG. 118 depicts an embodiment of two temperature limited heaterscoupled together in a single contacting section.

FIG. 119 depicts an embodiment of two temperature limited heaters withlegs coupled in a contacting section.

FIG. 120 depicts an embodiment of three diads coupled to a three-phasetransformer.

FIG. 121 depicts an embodiment of groups of diads in a hexagonalpattern.

FIG. 122 depicts an embodiment of diads in a triangular pattern.

FIG. 123 depicts a cross-sectional representation of an embodiment ofsubstantially u-shaped heaters in a formation.

FIG. 124 depicts a representational top view of an embodiment of asurface pattern of heaters depicted in FIG. 123.

FIG. 125 depicts a cross-sectional representation of substantiallyu-shaped heaters in a hydrocarbon layer.

FIG. 126 depicts a side view representation of an embodiment ofsubstantially vertical heaters coupled to a substantially horizontalwellbore.

FIG. 127 depicts an embodiment of pluralities of substantiallyhorizontal heaters coupled to bus bars in a hydrocarbon layer.

FIG. 128 depicts an embodiment of pluralities of substantiallyhorizontal heaters coupled to bus bars in a hydrocarbon layer.

FIG. 129 depicts an embodiment of a bus bar coupled to heaters withconnectors.

FIG. 130 depicts an embodiment of a bus bar coupled to heaters withconnectors and centralizers.

FIG. 131 depicts a representation of a connector coupling to a bus bar.

FIG. 132 depicts a perspective representation of a connector coupling toa bus bar.

FIG. 133 depicts an embodiment of three u-shaped heaters with commonoverburden sections coupled to a single three-phase transformer.

FIG. 134 depicts a top view representation of an embodiment of a heaterand a drilling guide in a wellbore.

FIG. 135 depicts a top view representation of an embodiment of twoheaters and a drilling guide in a wellbore.

FIG. 136 depicts a top view representation of an embodiment of threeheaters and a centralizer in a wellbore.

FIG. 137 depicts an embodiment for coupling ends of heaters in awellbore.

FIG. 138 depicts a schematic of an embodiment of multiple heatersextending in different directions from a wellbore.

FIG. 139 depicts a schematic of an embodiment of multiple levels ofheaters extending between two wellbores.

FIG. 140 depicts an embodiment of a u-shaped heater that has aninductively energized tubular.

FIG. 141 depicts an embodiment of an electrical conductor centralizedinside a tubular.

FIG. 142 depicts an embodiment of an induction heater with a sheath ofan insulated conductor in electrical contact with a tubular.

FIG. 143 depicts an embodiment of a resistive heater with a tubularhaving radial grooved surfaces.

FIG. 144 depicts an embodiment of an induction heater with a tubularhaving radial grooved surfaces.

FIG. 145 depicts an embodiment of a heater divided into tubular sectionsto provide varying heat outputs along the length of the heater.

FIG. 146 depicts an embodiment of three electrical conductors enteringthe formation through a first common wellbore and exiting the formationthrough a second common wellbore with three tubulars surrounding theelectrical conductors in the hydrocarbon layer.

FIG. 147 depicts a representation of an embodiment of three electricalconductors and three tubulars in separate wellbores in the formationcoupled to a transformer.

FIG. 148 depicts an embodiment of a multilayer induction tubular.

FIG. 149 depicts a cross-sectional end view of an embodiment of aninsulated conductor that is used as an induction heater.

FIG. 150 depicts a cross-sectional side view of the embodiment depictedin FIG. 149.

FIG. 151 depicts a cross-sectional end view of an embodiment of atwo-leg insulated conductor that is used as an induction heater.

FIG. 152 depicts a cross-sectional side view of the embodiment depictedin FIG. 151.

FIG. 153 depicts a cross-sectional end view of an embodiment of amultilayered insulated conductor that is used as an induction heater.

FIG. 154 depicts an end view representation of an embodiment of threeinsulated conductors located in a coiled tubing conduit and used asinduction heaters.

FIG. 155 depicts a representation of cores of insulated conductorscoupled together at their ends.

FIG. 156 depicts an end view representation of an embodiment of threeinsulated conductors strapped to a support member and used as inductionheaters.

FIG. 157 depicts a representation of an embodiment of an inductionheater with a core and an electrical insulator surrounded by aferromagnetic layer.

FIG. 158 depicts a representation of an embodiment of an insulatedconductor surrounded by a ferromagnetic layer.

FIG. 159 depicts a representation of an embodiment of an inductionheater with two ferromagnetic layers spirally wound onto a core and anelectrical insulator.

FIG. 160 depicts an embodiment for assembling a ferromagnetic layer ontoan insulated conductor.

FIG. 161 depicts an embodiment of a casing having an axial grooved orcorrugated surface.

FIG. 162 depicts an embodiment of a single-ended, substantiallyhorizontal insulated conductor heater that electrically isolates itselffrom the formation.

FIGS. 163A and 163B depict cross-sectional representations of anembodiment of an insulated conductor that is electrically isolated onthe outside of the jacket.

FIG. 164 depicts a side view representation with a cut out portion of anembodiment of an insulated conductor inside a tubular.

FIG. 165 depicts a cross-sectional representation of an embodiment of aninsulated conductor inside a tubular taken substantially along line A-Aof FIG. 164.

FIG. 166 depicts a cross-sectional representation of an embodiment of adistal end of an insulated conductor inside a tubular.

FIG. 167 depicts an embodiment of a wellhead.

FIG. 168 depicts an embodiment of a heater that has been installed intwo parts.

FIG. 169 depicts a top view representation of an embodiment of atransformer showing the windings and core of the transformer.

FIG. 170 depicts a side view representation of the embodiment of thetransformer showing the windings, the core, and the power leads.

FIG. 171 depicts an embodiment of a transformer in a wellbore.

FIG. 172 depicts an embodiment of a transformer in a wellbore with heatpipes.

FIG. 173 depicts a schematic for a conventional design of a tap changingvoltage regulator.

FIG. 174 depicts a schematic for a variable voltage, load tap changingtransformer.

FIG. 175 depicts a representation of an embodiment of a transformer anda controller.

FIG. 176 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a relativelythin hydrocarbon layer.

FIG. 177 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a hydrocarbonlayer that is thicker than the hydrocarbon layer depicted in FIG. 176.

FIG. 178 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a hydrocarbonlayer that is thicker than the hydrocarbon layer depicted in FIG. 177.

FIG. 179 depicts a side view representation of an embodiment forproducing mobilized fluids from a tar sands formation with a hydrocarbonlayer that has a shale break.

FIG. 180 depicts a top view representation of an embodiment forpreheating using heaters for the drive process.

FIG. 181 depicts a perspective representation of an embodiment forpreheating using heaters for the drive process.

FIG. 182 depicts a side view representation of an embodiment of a tarsands formation subsequent to a steam injection process.

FIG. 183 depicts a side view representation of an embodiment using atleast three treatment sections in a tar sands formation.

FIG. 184 depicts a representation of an embodiment for producinghydrocarbons from a tar sands formation.

FIG. 185 depicts a representation of an embodiment for producinghydrocarbons from multiple layers in a tar sands formation.

FIG. 186 depicts an embodiment for heating and producing from aformation with a temperature limited heater in a production wellbore.

FIG. 187 depicts an embodiment for heating and producing from aformation with a temperature limited heater and a production wellbore.

FIG. 188 depicts a schematic of an embodiment of a first stage oftreating a tar sands formation with electrical heaters.

FIG. 189 depicts a schematic of an embodiment of a second stage oftreating the tar sands formation with fluid injection and oxidation.

FIG. 190 depicts a schematic of an embodiment of a third stage oftreating the tar sands formation with fluid injection and oxidation.

FIG. 191 depicts a side view representation of a first stage of anembodiment of treating portions in a subsurface formation with heaters,oxidation and/or fluid injection.

FIG. 192 depicts a side view representation of a second stage of anembodiment of treating portions in the subsurface formation withheaters, oxidation and/or fluid injection.

FIG. 193 depicts a side view representation of an embodiment of treatingportions in subsurface formation with heaters, oxidation and/or fluidinjection.

FIG. 194 depicts an embodiment of treating a subsurface formation usinga cylindrical pattern.

FIG. 195 depicts an embodiment of treating multiple portions of asubsurface formation in a rectangular pattern.

FIG. 196 is a schematic top view of the pattern depicted in FIG. 195.

FIG. 197 depicts a schematic representation of an embodiment of adownhole oxidizer assembly.

FIG. 198 depicts a schematic representation of an embodiment of a systemfor producing fuel for downhole oxidizer assemblies.

FIG. 199 depicts a schematic representation of an embodiment of a systemfor producing oxygen for use in downhole oxidizer assemblies.

FIG. 200 depicts a schematic representation of an embodiment of a systemfor producing oxygen for use in downhole oxidizer assemblies.

FIG. 201 depicts a schematic representation of an embodiment of a systemfor producing hydrogen for use in downhole oxidizer assemblies.

FIG. 202 depicts a cross-sectional representation of an embodiment of adownhole oxidizer including an insulating sleeve.

FIG. 203 depicts a cross-sectional representation of an embodiment of adownhole oxidizer with a gas cooled insulating sleeve.

FIG. 204 depicts a perspective view of an embodiment of a portion of anoxidizer of a downhole oxidizer assembly.

FIG. 205 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 206 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 207 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 208 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 209 depicts a cross-sectional representation of an embodiment of anoxidizer shield with multiple flame stabilizers.

FIG. 210 depicts a cross-sectional representation of an embodiment of anoxidizer shield.

FIG. 211 depicts a perspective representation of an embodiment of aportion of an oxidizer of a downhole oxidizer assembly with louveredopenings in the shield.

FIG. 212 depicts a cross-sectional representation of a portion of ashield with a louvered opening.

FIG. 213 depicts a perspective representation of an embodiment of asectioned oxidizer.

FIG. 214 depicts a perspective representation of an embodiment of asectioned oxidizer.

FIG. 215 depicts a perspective representation of an embodiment of asectioned oxidizer.

FIG. 216 depicts a cross-sectional representation of an embodiment of afirst oxidizer of an oxidizer assembly.

FIG. 217 depicts a cross-sectional representation of an embodiment of acatalytic burner.

FIG. 218 depicts a cross-sectional representation of an embodiment of acatalytic burner with an igniter.

FIG. 219 depicts a cross-sectional representation of an oxidizerassembly.

FIG. 220 depicts a cross-sectional representation of an oxidizer of anoxidizer assembly.

FIG. 221 depicts a schematic representation of an oxidizer assembly withflameless distributed combustors and oxidizers.

FIG. 222 depicts a schematic representation of an embodiment of adownhole oxidizer assembly.

FIG. 223 depicts a schematic representation of an embodiment of adownhole oxidizer assembly.

FIG. 224 depicts a schematic representation of an embodiment of a heaterthat uses coal as fuel.

FIG. 225 depicts a schematic representation of an embodiment of a heaterthat uses coal as fuel.

FIG. 226 depicts an embodiment of a heater with a heating sectionlocated in a u-shaped wellbore to create a first heated volume.

FIG. 227 depicts an embodiment of a heater with a heating sectionlocated in a u-shaped wellbore to create a second heated volume.

FIG. 228 depicts an embodiment of a heater with a heating sectionlocated in a u-shaped wellbore to create a third heated volume.

FIG. 229 depicts an embodiment of a heater with a heating sectionlocated in an L-shaped or J-shaped wellbore to create a first heatedvolume.

FIG. 230 depicts an embodiment of a heater with a heating sectionlocated in an L-shaped or J-shaped wellbore to create a second heatedvolume.

FIG. 231 depicts an embodiment of a heater with a heating sectionlocated in an L-shaped or J-shaped wellbore to create a third heatedvolume.

FIG. 232 depicts an embodiment of two heaters with heating sectionslocated in a u-shaped wellbore to create two heated volumes.

FIG. 233 depicts a schematic representation of an embodiment of adownhole fluid heating system.

FIG. 234 depicts an embodiment of a wellbore for heating a formationusing a burning fuel moving through the formation.

FIG. 235 depicts a top view representation of a portion of the fueltrain used to heat the treatment area.

FIG. 236 depicts a side view representation of a portion of the fueltrain used to heat the treatment area.

FIG. 237 depicts an aerial view representation of a system that heatsthe treatment area using burning fuel that is moved through thetreatment area.

FIG. 238 depicts a schematic representation of a heat transfer fluidcirculation system for heating a portion of a formation.

FIG. 239 depicts a schematic representation of an embodiment of anL-shaped heater for use with a heat transfer fluid circulation systemfor heating a portion of a formation.

FIG. 240 depicts a schematic representation of an embodiment of avertical heater for use with a heat transfer fluid circulation systemfor a heating a portion of a formation where thermal expansion of theheater is accommodated below the surface.

FIG. 241 depicts a schematic representation of an embodiment of avertical heater for use with a heat transfer fluid circulation systemfor a heating a portion of a formation where thermal expansion of theheater is accommodated above and below the surface.

FIG. 242 depicts a schematic representation of a portion of formationthat is treated using a corridor pattern system.

FIG. 243 depicts a schematic representation of a portion of formationthat is treated using a radial pattern system.

FIG. 244 depicts a plan view of wellbore entries and exits from aportion of a formation to be heated using a closed loop circulationsystem.

FIG. 245 depicts a cross-sectional view of an embodiment of overburdeninsulation that utilizes insulating cement.

FIG. 246 depicts a cross-sectional view of an embodiment of overburdeninsulation that utilizes an insulating sleeve.

FIG. 247 depicts a cross-sectional view of an embodiment of overburdeninsulation that utilizes an insulating sleeve and a vacuum.

FIG. 248 depicts a representation of bellows used to accommodate thermalexpansion.

FIG. 249 depicts a representation of piping with an expansion loop foraccommodating thermal expansion.

FIG. 250 depicts a representation of insulated piping in a largediameter casing in the overburden.

FIG. 251 depicts a representation of insulated piping in a largediameter casing in the overburden to accommodate thermal expansion.

FIG. 252 depicts a representation of an embodiment of a wellhead with asliding seal, stuffing box or other pressure control equipment thatallows a portion of a heater to move relative to the wellhead.

FIG. 253 depicts a representation of an embodiment of wellhead with aslip joint that interacts with a fixed conduit above the wellhead.

FIG. 254 depicts a representation of an embodiment of wellhead with aslip joint that interacts with a fixed conduit coupled to the wellhead.

FIG. 255 depicts a representation of a u-shaped wellbore with hot heattransfer fluid circulation system heater positioned in the wellbore.

FIG. 256 depicts a side view representation of an embodiment of a systemfor heating the formation that can use a closed loop circulation systemand/or electrical heating.

FIG. 257 depicts a representation of a heat transfer fluid conduit thatmay initially be resistively heated with the return current pathprovided by an insulated conductor.

FIG. 258 depicts a representation of a heat transfer fluid conduit thatmay initially be resistively heated with the return current pathprovided by two insulated conductors.

FIG. 259 depicts a representation of insulated conductors used toresistively heat heaters of a circulated fluid heating system.

FIG. 260 depicts a representation of a heater of a heat transfer fluidcirculation system with an insulated conductor heater positioned in thepiping.

FIG. 261 depicts a cross-sectional view of an embodiment of aconduit-in-conduit heater for a heat transfer circulation heating systemadjacent to the treatment area.

FIG. 262 depicts a schematic of an embodiment of conduit-in-conduitheaters of a fluid circulation heating system positioned in theformation.

FIG. 263 depicts a cross-sectional view of an embodiment of aconduit-in-conduit heater adjacent to the overburden.

FIG. 264 depicts an embodiment of a circulation system for a liquid heattransfer fluid.

FIG. 265 depicts a schematic representation of an embodiment of a systemfor heating the formation using gas lift to return the heat transferfluid to the surface.

FIG. 266 depicts a schematic representation of an embodiment of an insitu heat treatment system that uses a nuclear reactor.

FIG. 267 depicts an elevational view of an in situ heat treatment systemusing pebble bed reactors.

FIG. 268 depicts a schematic representation of an embodiment of aself-regulating nuclear reactor.

FIG. 269 depicts power (W/ft) (y-axis) versus time (yr) (x-axis) of insitu hydrocarbon remediation power injection requirements.

FIG. 270 depicts power (W/ft) (y-axis) versus time (days) (x-axis) of insitu hydrocarbon remediation power injection requirements for differentspacings between wellbores.

FIG. 271 depicts reservoir average temperature (° C.) (y-axis) versustime (days) (x-axis) of in situ hydrocarbon remediation for differentspacings between wellbores.

FIG. 272 depicts a schematic representation of an embodiment of an insitu heat treatment system with u-shaped wellbores using self-regulatingnuclear reactors.

FIG. 273 depicts a side view representation of an embodiment for an insitu staged heating and production process for treating a tar sandsformation.

FIG. 274 depicts a top view of a rectangular checkerboard patternembodiment for the in situ staged heating and production process.

FIG. 275 depicts a top view of a ring pattern embodiment for the in situstaged heating and production process.

FIG. 276 depicts a top view of a checkerboard ring pattern embodimentfor the in situ staged heating and production process.

FIG. 277 depicts a top view an embodiment of a plurality of rectangularcheckerboard patterns in a treatment area for the in situ staged heatingand production process.

FIG. 278 depicts an embodiment of irregular spaced heat sources with theheater density increasing as distance from a production well increases.

FIG. 279 depicts an embodiment of an irregular spaced triangularpattern.

FIG. 280 depicts an embodiment of irregular spaced square pattern.

FIG. 281 depicts an embodiment of a regular pattern of equally spacedrows of heat sources.

FIG. 282 depicts an embodiment of irregular spaced heat sources definingvolumes around a production well.

FIG. 283 depicts an embodiment of a repeated pattern of irregular spacedheat sources with the heater density of each pattern increasing asdistance from the production well increases.

FIG. 284 depicts a side view representation of embodiments for producingmobilized fluids from a hydrocarbon formation.

FIG. 285 depicts a side view representation of an embodiment forproducing mobilized fluids from a hydrocarbon formation heated byresidual heat.

FIG. 286 depicts a schematic representation of a system for inhibitingmigration of formation fluid from a treatment area.

FIG. 287 depicts an embodiment of a windmill for generating electricityfor subsurface heaters.

FIG. 288 depicts an embodiment of a solution mining well.

FIG. 289 depicts a representation of a portion of a solution miningwell.

FIG. 290 depicts a representation of a portion of a solution miningwell.

FIG. 291 depicts an elevational view of a well pattern for solutionmining and/or an in situ heat treatment process.

FIG. 292 depicts a representation of wells of an in situ heatingtreatment process for solution mining and producing hydrocarbons from aformation.

FIG. 293 depicts an embodiment for solution mining a formation.

FIG. 294 depicts an embodiment of a formation with nahcolite layers inthe formation before solution mining nahcolite from the formation.

FIG. 295 depicts the formation of FIG. 294 after the nahcolite has beensolution mined.

FIG. 296 depicts an embodiment of two injection wells interconnected bya zone that has been solution mined to remove nahcolite from the zone.

FIG. 297 depicts a representation of an embodiment for treating aportion of a formation having a hydrocarbon containing formation betweenan upper nahcolite bed above and a lower nahcolite bed.

FIG. 298 depicts a representation of a portion of the formation that isorthogonal to the formation depicted in FIG. 297 and passes through oneof the solution mining wells in the upper nahcolite bed.

FIG. 299 depicts an embodiment for heating a formation with dawsonite inthe formation.

FIG. 300 depicts a representation of an embodiment for solution miningwith a steam and electricity cogeneration facility.

FIG. 301 depicts an embodiment of treating a hydrocarbon containingformation with a combustion front.

FIG. 302 depicts a representation of an embodiment for treating ahydrocarbon containing formation with a combustion front.

FIG. 303 depicts a schematic representation of a system for producingformation fluid and introducing sour gas into a subsurface formation.

FIG. 304 depicts a schematic representation of a circulated fluidcooling system.

FIG. 305 depicts a schematic of an embodiment for treating a subsurfaceformation using heat sources having electrically conductive material.

FIG. 306 depicts a schematic of an embodiment for treating a subsurfaceformation using a ground and heat sources having electrically conductivematerial.

FIG. 307 depicts a schematic of an embodiment for treating a subsurfaceformation using heat sources having electrically conductive material andan electrical insulator.

FIG. 308 depicts a schematic of an embodiment for treating a subsurfaceformation using electrically conductive heat sources extending from acommon wellbore.

FIG. 309 depicts a schematic of an embodiment for treating a subsurfaceformation having a shale layer using heat sources having electricallyconductive material.

FIGS. 310A,B depict schematics of embodiments of an uncoated electrodeand an electrode with a coated end, respectively.

FIGS. 311A,B depict schematics of embodiments of an uncoated electrodeand a coated electrode, respectively.

FIG. 312 depicts a perspective view of an embodiment of an undergroundtreatment system.

FIG. 313 depicts a perspective view of tunnels of an embodiment of anunderground treatment system.

FIG. 314 depicts another exploded perspective view of a portion of anunderground treatment system and tunnels.

FIG. 315 depicts a side view representation of an embodiment for flowingheated fluid through heat sources between tunnels.

FIG. 316 depicts a top view representation of an embodiment for flowingheated fluid through heat sources between tunnels.

FIG. 317 depicts a perspective view of an embodiment of an undergroundtreatment system having heater wellbores spanning between to two tunnelsof the underground treatment system.

FIG. 318 depicts a top view of an embodiment of tunnels with wellborechambers.

FIG. 319 depicts a schematic view of tunnel sections of an embodiment ofan underground treatment system.

FIG. 320 depicts a schematic view of an embodiment of an undergroundtreatment system with surface production.

FIG. 321 depicts a side view of an embodiment of an undergroundtreatment system.

FIG. 322 depicts electrical resistance versus temperature at variousapplied electrical currents for a 446 stainless steel rod.

FIG. 323 shows resistance profiles as a function of temperature atvarious applied electrical currents for a copper rod contained in aconduit of Sumitomo HCM12A.

FIG. 324 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 325 depicts raw data for a temperature limited heater.

FIG. 326 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 327 depicts power versus temperature at various applied electricalcurrents for a temperature limited heater.

FIG. 328 depicts electrical resistance versus temperature at variousapplied electrical currents for a temperature limited heater.

FIG. 329 depicts data of electrical resistance versus temperature for asolid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at variousapplied electrical currents.

FIG. 330 depicts data of electrical resistance versus temperature for acomposite 1.9 cm, 1.8 m long alloy 42-6 rod with a copper core (the rodhas an outside diameter to copper diameter ratio of 2:1) at variousapplied electrical currents.

FIG. 331 depicts data of power output versus temperature for a composite1.9 cm diameter, 1.8 m long alloy 42-6 rod with a copper core (the rodhas an outside diameter to copper diameter ratio of 2:1) at variousapplied electrical currents.

FIG. 332 depicts data for values of skin depth versus temperature for asolid 2.54 cm diameter, 1.8 m long 410 stainless steel rod at variousapplied AC electrical currents.

FIG. 333 depicts temperature versus time for a temperature limitedheater.

FIG. 334 depicts temperature versus log time data for a 2.5 cm diametersolid 410 stainless steel rod and a 2.5 cm diameter solid 304 stainlesssteel rod.

FIG. 335 depicts experimentally measured resistance versus temperatureat several currents for a temperature limited heater with a copper core,a carbon steel ferromagnetic conductor, and a 347H stainless steelsupport member.

FIG. 336 depicts experimentally measured resistance versus temperatureat several currents for a temperature limited heater with a copper core,an iron-cobalt ferromagnetic conductor, and a 347H stainless steelsupport member.

FIG. 337 depicts experimentally measured power factor versus temperatureat two AC currents for a temperature limited heater with a copper core,a carbon steel ferromagnetic conductor, and a 347H stainless steelsupport member.

FIG. 338 depicts experimentally measured turndown ratio versus maximumpower delivered for a temperature limited heater with a copper core, acarbon steel ferromagnetic conductor, and a 347H stainless steel supportmember.

FIG. 339 depicts examples of relative magnetic permeability versusmagnetic field for both the found correlations and raw data for carbonsteel.

FIG. 340 shows the resulting plots of skin depth versus magnetic fieldfor four temperatures and 400 A current.

FIG. 341 shows a comparison between the experimental and numerical(calculated) AC resistances for currents of 300 A, 400 A, and 500 A.

FIG. 342 shows the AC resistance per foot of the heater element as afunction of skin depth at 1100° F. calculated from the theoreticalmodel.

FIG. 343 depicts the power generated per unit length in each heatercomponent versus skin depth for a temperature limited heater.

FIGS. 344A-C compare the results of theoretical calculations withexperimental data for resistance versus temperature in a temperaturelimited heater.

FIG. 345 depicts a plot of heater power versus core diameter.

FIG. 346 depicts power, resistance, and current versus temperature for aheater with a core diameter of 0.105″.

FIG. 347 depicts actual heater power versus time during the simulationfor three different heater designs.

FIG. 348 depicts heater element temperature (core temperature) andaverage formation temperature versus time for three different heaterdesigns.

FIG. 349 depicts plots of power versus temperature at three currents foran induction heater.

FIG. 350 depicts temperature versus radial distance for a heater withair between an insulated conductor and conduit.

FIG. 351 depicts temperature versus radial distance for a heater withmolten solar salt between an insulated conductor and conduit.

FIG. 352 depicts temperature versus radial distance for a heater withmolten tin between an insulated conductor and conduit.

FIG. 353 depicts simulated temperature versus radial distance forvarious heaters of a first size, with various fluids between theinsulated conductors and conduits, and at different temperatures of theouter surfaces of the conduits.

FIG. 354 depicts simulated temperature versus radial distance forvarious heaters wherein the dimensions of the insulated conductor arehalf the size of the insulated conductor used to generate FIG. 353, withvarious fluids between the insulated conductors and conduits, and atdifferent temperatures of the outer surfaces of the conduits.

FIG. 355 depicts simulated temperature versus radial distance forvarious heaters wherein the dimensions of the insulated conductor is thesame as the insulated conductor used to generate FIG. 354, and theconduit is larger than the conduit used to generate FIG. 354 withvarious fluids between the insulated conductors and conduits, and atvarious temperatures of the outer surfaces of the conduits.

FIG. 356 depicts simulated temperature versus radial distance forvarious heaters with molten salt between insulated conductors andconduits of the heaters and a boundary condition of 500° C.

FIG. 357 depicts a temperature profile in the formation after 360 daysusing the STARS simulation.

FIG. 358 depicts an oil saturation profile in the formation after 360days using the STARS simulation.

FIG. 359 depicts the oil saturation profile in the formation after 1095days using the STARS simulation.

FIG. 360 depicts the oil saturation profile in the formation after 1470days using the STARS simulation.

FIG. 361 depicts the oil saturation profile in the formation after 1826days using the STARS simulation.

FIG. 362 depicts the temperature profile in the formation after 1826days using the STARS simulation.

FIG. 363 depicts oil production rate and gas production rate versustime.

FIG. 364 depicts weight percentage of original bitumen in place (OBIP)(left axis) and volume percentage of OBIP (right axis) versustemperature (° C.).

FIG. 365 depicts bitumen conversion percentage (weight percentage of(OBIP)) (left axis) and oil, gas, and coke weight percentage (as aweight percentage of OBIP) (right axis) versus temperature (° C.).

FIG. 366 depicts API gravity (°) (left axis) of produced fluids, blowdown production, and oil left in place along with pressure (psig) (rightaxis) versus temperature (° C.).

FIGS. 367A-D depict gas-to-oil ratios (GOR) in thousand cubic feet perbarrel ((Mcf/bbl) (y-axis)) versus temperature (° C.) (x-axis) fordifferent types of gas at a low temperature blow down (about 277° C.)and a high temperature blow down (at about 290° C.).

FIG. 368 depicts coke yield (weight percentage) (y-axis) versustemperature (° C.) (x-axis).

FIGS. 369A-D depict assessed hydrocarbon isomer shifts in fluidsproduced from the experimental cells as a function of temperature andbitumen conversion.

FIG. 370 depicts weight percentage (Wt %) (y-axis) of saturates fromSARA analysis of the produced fluids versus temperature (° C.) (x-axis).

FIG. 371 depicts weight percentage (Wt %) (y-axis) of n-C₇ of theproduced fluids versus temperature (° C.) (x-axis).

FIG. 372 depicts oil recovery (volume percentage bitumen in place (vol %BIP)) versus API gravity (°) as determined by the pressure (MPa) in theformation in an experiment.

FIG. 373 depicts recovery efficiency (%) versus temperature (° C.) atdifferent pressures in an experiment.

FIG. 374 depicts average formation temperature (° C.) versus days forheating a formation using molten salt circulated throughconduit-in-conduit heaters.

FIG. 375 depicts molten salt temperature (° C.) and power injection rate(W/ft) versus time (days).

FIG. 376 depicts temperature (° C.) and power injection rate (W/ft)versus time (days) for heating a formation using molten salt circulatedthrough heaters with a heating length of 8000 ft at a mass flow rate of18 kg/s.

FIG. 377 depicts temperature (° C.) and power injection rate (W/ft)versus time (days) for heating a formation using molten salt circulatedthrough heaters with a heating length of 8000 ft at a mass flow rate of12 kg/s.

While the invention is susceptible to various modifications andalternative forms, specific embodiments thereof are shown by way ofexample in the drawings and may herein be described in detail. Thedrawings may not be to scale. It should be understood, however, that thedrawings and detailed description thereto are not intended to limit theinvention to the particular form disclosed, but on the contrary, theintention is to cover all modifications, equivalents and alternativesfalling within the spirit and scope of the present invention as definedby the appended claims.

DETAILED DESCRIPTION

The following description generally relates to systems and methods fortreating hydrocarbons in the formations. Such formations may be treatedto yield hydrocarbon products, hydrogen, and other products.

“Alternating current (AC)” refers to a time-varying current thatreverses direction substantially sinusoidally. AC produces skin effectelectricity flow in a ferromagnetic conductor.

“Annular region” is the region between an outer conduit and an innerconduit positioned in the outer conduit.

“API gravity” refers to API gravity at 15.5° C. (60° F.). API gravity isas determined by ASTM Method D6822 or ASTM Method D1298.

“ASTM” refers to American Standard Testing and Materials.

In the context of reduced heat output heating systems, apparatus, andmethods, the term “automatically” means such systems, apparatus, andmethods function in a certain way without the use of external control(for example, external controllers such as a controller with atemperature sensor and a feedback loop, PID controller, or predictivecontroller).

“Bare metal” and “exposed metal” refer to metals of elongated membersthat do not include a layer of electrical insulation, such as mineralinsulation, that is designed to provide electrical insulation for themetal throughout an operating temperature range of the elongated member.Bare metal and exposed metal may encompass a metal that includes acorrosion inhibiter such as a naturally occurring oxidation layer, anapplied oxidation layer, and/or a film. Bare metal and exposed metalinclude metals with polymeric or other types of electrical insulationthat cannot retain electrical insulating properties at typical operatingtemperature of the elongated member. Such material may be placed on themetal and may be thermally degraded during use of the heater.

Boiling range distributions for the formation fluid and liquid streamsdescribed herein are as determined by ASTM Method D5307 or ASTM MethodD2887. Content of hydrocarbon components in weight percent forparaffins, iso-paraffins, olefins, naphthenes and aromatics in theliquid streams is as determined by ASTM Method D6730. Content ofaromatics in volume percent is as determined by ASTM Method D1319.Weight percent of hydrogen in hydrocarbons is as determined by ASTMMethod D3343.

“Bromine number” refers to a weight percentage of olefins in grams per100 gram of portion of the produced fluid that has a boiling range below246° C. and testing the portion using ASTM Method D1159.

“Carbon number” refers to the number of carbon atoms in a molecule. Ahydrocarbon fluid may include various hydrocarbons with different carbonnumbers. The hydrocarbon fluid may be described by a carbon numberdistribution. Carbon numbers and/or carbon number distributions may bedetermined by true boiling point distribution and/or gas-liquidchromatography.

“Chemically stability” refers to the ability of a formation fluid to betransported without components in the formation fluid reacting to formpolymers and/or compositions that plug pipelines, valves, and/orvessels.

“Clogging” refers to impeding and/or inhibiting flow of one or morecompositions through a process vessel or a conduit.

“Column X element” or “Column X elements” refer to one or more elementsof Column X of the Periodic Table, and/or one or more compounds of oneor more elements of Column X of the Periodic Table, in which Xcorresponds to a column number (for example, 13-18) of the PeriodicTable. For example, “Column 15 elements” refer to elements from Column15 of the Periodic Table and/or compounds of one or more elements fromColumn 15 of the Periodic Table.

“Column X metal” or “Column X metals” refer to one or more metals ofColumn X of the Periodic Table and/or one or more compounds of one ormore metals of Column X of the Periodic Table, in which X corresponds toa column number (for example, 1-12) of the Periodic Table. For example,“Column 6 metals” refer to metals from Column 6 of the Periodic Tableand/or compounds of one or more metals from Column 6 of the PeriodicTable.

“Condensable hydrocarbons” are hydrocarbons that condense at 25° C. andone atmosphere absolute pressure. Condensable hydrocarbons may include amixture of hydrocarbons having carbon numbers greater than 4.“Non-condensable hydrocarbons” are hydrocarbons that do not condense at25° C. and one atmosphere absolute pressure. Non-condensablehydrocarbons may include hydrocarbons having carbon numbers less than 5.

“Coring” is a process that generally includes drilling a hole into aformation and removing a substantially solid mass of the formation fromthe hole.

“Cracking” refers to a process involving decomposition and molecularrecombination of organic compounds to produce a greater number ofmolecules than were initially present. In cracking, a series ofreactions take place accompanied by a transfer of hydrogen atoms betweenmolecules. For example, naphtha may undergo a thermal cracking reactionto form ethene and H₂.

“Curie temperature” is the temperature above which a ferromagneticmaterial loses all of its ferromagnetic properties. In addition tolosing all of its ferromagnetic properties above the Curie temperature,the ferromagnetic material begins to lose its ferromagnetic propertieswhen an increasing electrical current is passed through theferromagnetic material.

“Cycle oil” refers to a mixture of light cycle oil and heavy cycle oil.“Light cycle oil” refers to hydrocarbons having a boiling rangedistribution between 430° F. (221° C.) and 650° F. (343° C.) that areproduced from a fluidized catalytic cracking system. Light cycle oilcontent is determined by ASTM Method D5307. “Heavy cycle oil” refers tohydrocarbons having a boiling range distribution between 650° F. (343°C.) and 800° F. (427° C.) that are produced from a fluidized catalyticcracking system. Heavy cycle oil content is determined by ASTM MethodD5307.

“Diad” refers to a group of two items (for example, heaters, wellbores,or other objects) coupled together.

“Diesel” refers to hydrocarbons with a boiling range distributionbetween 260° C. and 343° C. (500-650° F.) at 0.101 MPa. Diesel contentis determined by ASTM Method D2887.

“Enriched air” refers to air having a larger mole fraction of oxygenthan air in the atmosphere. Air is typically enriched to increasecombustion-supporting ability of the air.

“Fluid injectivity” is the flow rate of fluids injected per unit ofpressure differential between a first location and a second location.

“Fluid pressure” is a pressure generated by a fluid in a formation.“Lithostatic pressure” (sometimes referred to as “lithostatic stress”)is a pressure in a formation equal to a weight per unit area of anoverlying rock mass. “Hydrostatic pressure” is a pressure in a formationexerted by a column of water.

A “formation” includes one or more hydrocarbon containing layers, one ormore non-hydrocarbon layers, an overburden, and/or an underburden.“Hydrocarbon layers” refer to layers in the formation that containhydrocarbons. The hydrocarbon layers may contain non-hydrocarbonmaterial and hydrocarbon material. The “overburden” and/or the“underburden” include one or more different types of impermeablematerials. For example, the overburden and/or underburden may includerock, shale, mudstone, or wet/tight carbonate. In some embodiments of insitu heat treatment processes, the overburden and/or the underburden mayinclude a hydrocarbon containing layer or hydrocarbon containing layersthat are relatively impermeable and are not subjected to temperaturesduring in situ heat treatment processing that result in significantcharacteristic changes of the hydrocarbon containing layers of theoverburden and/or the underburden. For example, the underburden maycontain shale or mudstone, but the underburden is not allowed to heat topyrolysis temperatures during the in situ heat treatment process. Insome cases, the overburden and/or the underburden may be somewhatpermeable.

“Formation fluids” refer to fluids present in a formation and mayinclude pyrolyzation fluid, synthesis gas, mobilized hydrocarbons, andwater (steam). Formation fluids may include hydrocarbon fluids as wellas non-hydrocarbon fluids. The term “mobilized fluid” refers to fluidsin a hydrocarbon containing formation that are able to flow as a resultof thermal treatment of the formation. “Produced fluids” refer to fluidsremoved from the formation.

“Freezing point” of a hydrocarbon liquid refers to the temperature belowwhich solid hydrocarbon crystals may form in the liquid. Freezing pointis as determined by ASTM Method D5901.

“Gasoline hydrocarbons” refer to hydrocarbons having a boiling pointrange from 32° C. (90° F.) to about 204° C. (400° F.). Gasolinehydrocarbons include, but are not limited to, straight run gasoline,naphtha, fluidized or thermally catalytically cracked gasoline, VBgasoline, and coker gasoline. Gasoline hydrocarbons content isdetermined by ASTM Method D2887.

A “heat source” is any system for providing heat to at least a portionof a formation substantially by conductive and/or radiative heattransfer. For example, a heat source may include electric heaters suchas an insulated conductor, an elongated member, and/or a conductordisposed in a conduit. A heat source may also include systems thatgenerate heat by burning a fuel external to or in a formation. Thesystems may be surface burners, downhole gas burners, flamelessdistributed combustors, and natural distributed combustors. In someembodiments, heat provided to or generated in one or more heat sourcesmay be supplied by other sources of energy. The other sources of energymay directly heat a formation, or the energy may be applied to atransfer medium that directly or indirectly heats the formation. It isto be understood that one or more heat sources that are applying heat toa formation may use different sources of energy. Thus, for example, fora given formation some heat sources may supply heat from electricresistance heaters, some heat sources may provide heat from combustion,and some heat sources may provide heat from one or more other energysources (for example, chemical reactions, solar energy, wind energy,biomass, or other sources of renewable energy). A chemical reaction mayinclude an exothermic reaction (for example, an oxidation reaction). Aheat source may also include a heater that provides heat to a zoneproximate and/or surrounding a heating location such as a heater well.

A “heater” is any system or heat source for generating heat in a well ora near wellbore region. Heaters may be, but are not limited to, electricheaters, burners, combustors that react with material in or producedfrom a formation, and/or combinations thereof.

“Heavy hydrocarbons” are viscous hydrocarbon fluids. Heavy hydrocarbonsmay include highly viscous hydrocarbon fluids such as heavy oil, tar,and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, aswell as smaller concentrations of sulfur, oxygen, and nitrogen.Additional elements may also be present in heavy hydrocarbons in traceamounts. Heavy hydrocarbons may be classified by API gravity. Heavyhydrocarbons generally have an API gravity below about 20°. Heavy oil,for example, generally has an API gravity of about 10-20°, whereas targenerally has an API gravity below about 10°. The viscosity of heavyhydrocarbons is generally greater than about 100 centipoise at 15° C.Heavy hydrocarbons may include aromatics or other complex ringhydrocarbons.

Heavy hydrocarbons may be found in a relatively permeable formation. Therelatively permeable formation may include heavy hydrocarbons entrainedin, for example, sand or carbonate. “Relatively permeable” is defined,with respect to formations or portions thereof, as an averagepermeability of 10 millidarcy or more (for example, 10 or 100millidarcy). “Relatively low permeability” is defined, with respect toformations or portions thereof, as an average permeability of less thanabout 10 millidarcy. One darcy is equal to about 0.99 squaremicrometers. An impermeable layer generally has a permeability of lessthan about 0.1 millidarcy.

Certain types of formations that include heavy hydrocarbons may alsoinclude, but are not limited to, natural mineral waxes, or naturalasphaltites. “Natural mineral waxes” typically occur in substantiallytubular veins that may be several meters wide, several kilometers long,and hundreds of meters deep. “Natural asphaltites” include solidhydrocarbons of an aromatic composition and typically occur in largeveins. In situ recovery of hydrocarbons from formations such as naturalmineral waxes and natural asphaltites may include melting to form liquidhydrocarbons and/or solution mining of hydrocarbons from the formations.

“Hydrocarbons” are generally defined as molecules formed primarily bycarbon and hydrogen atoms. Hydrocarbons may also include other elementssuch as, but not limited to, halogens, metallic elements, nitrogen,oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to,kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, andasphaltites. Hydrocarbons may be located in or adjacent to mineralmatrices in the earth. Matrices may include, but are not limited to,sedimentary rock, sands, silicilytes, carbonates, diatomites, and otherporous media. “Hydrocarbon fluids” are fluids that include hydrocarbons.Hydrocarbon fluids may include, entrain, or be entrained innon-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide,carbon dioxide, hydrogen sulfide, water, and ammonia.

An “in situ conversion process” refers to a process of heating ahydrocarbon containing formation from heat sources to raise thetemperature of at least a portion of the formation above a pyrolysistemperature so that pyrolyzation fluid is produced in the formation.

An “in situ heat treatment process” refers to a process of heating ahydrocarbon containing formation with heat sources to raise thetemperature of at least a portion of the formation above a temperaturethat results in mobilized fluid, visbreaking, and/or pyrolysis ofhydrocarbon containing material so that mobilized fluids, visbrokenfluids, and/or pyrolyzation fluids are produced in the formation.

“Insulated conductor” refers to any elongated material that is able toconduct electricity and that is covered, in whole or in part, by anelectrically insulating material.

“Karst” is a subsurface shaped by the dissolution of a soluble layer orlayers of bedrock, usually carbonate rock such as limestone or dolomite.The dissolution may be caused by meteoric or acidic water. The Grosmontformation in Alberta, Canada is an example of a karst (or “karsted”)carbonate formation.

“Kerogen” is a solid, insoluble hydrocarbon that has been converted bynatural degradation and that principally contains carbon, hydrogen,nitrogen, oxygen, and sulfur. Coal and oil shale are typical examples ofmaterials that contain kerogen. “Bitumen” is a non-crystalline solid orviscous hydrocarbon material that is substantially soluble in carbondisulfide. “Oil” is a fluid containing a mixture of condensablehydrocarbons.

“Kerosene” refers to hydrocarbons with a boiling range distributionbetween 204° C. and 260° C. at 0.101 MPa. Kerosene content is determinedby ASTM Method D2887.

“Modulated direct current (DC)” refers to any substantiallynon-sinusoidal time-varying current that produces skin effectelectricity flow in a ferromagnetic conductor.

“Naphtha” refers to hydrocarbon components with a boiling rangedistribution between 38° C. and 200° C. at 0.101 MPa. Naphtha content isdetermined by ASTM Method D5307.

“Nitride” refers to a compound of nitrogen and one or more otherelements of the Periodic Table. Nitrides include, but are not limitedto, silicon nitride, boron nitride, or alumina nitride.

“Nitrogen compound content” refers to an amount of nitrogen in anorganic compound. Nitrogen content is as determined by ASTM MethodD5762.

“Octane Number” refers to a calculated numerical representation of theantiknock properties of a motor fuel compared to a standard referencefuel. A calculated octane number is determined by ASTM Method D6730.

“Olefins” are molecules that include unsaturated hydrocarbons having oneor more non-aromatic carbon-carbon double bonds.

“Olefin content” refers to an amount of non-aromatic olefins in a fluid.Olefin content for a produced fluid is determined by obtaining a portionof the produce fluid that has a boiling point of 246° C. and testing theportion using ASTM Method D1159 and reporting the result as a brominefactor in grams per 100 gram of portion. Olefin content is alsodetermined by the Canadian Association of Petroleum Producers (CAPP)olefin method and is reported in percent olefin as 1-decene equivalent.

“Organonitrogen compounds” refers to hydrocarbons that contain at leastone nitrogen atom. Non-limiting examples of organonitrogen compoundsinclude, but are not limited to, alkyl amines, aromatic amines, alkylamides, aromatic amides, pyridines, pyrazoles, and oxazoles.

“Orifices” refer to openings, such as openings in conduits, having awide variety of sizes and cross-sectional shapes including, but notlimited to, circles, ovals, squares, rectangles, triangles, slits, orother regular or irregular shapes.

“P (peptization) value” or “P-value” refers to a numerical value, whichrepresents the flocculation tendency of asphaltenes in a formationfluid. P-value is determined by ASTM method D7060.

“Perforations” include openings, slits, apertures, or holes in a wall ofa conduit, tubular, pipe or other flow pathway that allow flow into orout of the conduit, tubular, pipe or other flow pathway.

“Periodic Table” refers to the Periodic Table as specified by theInternational Union of Pure and Applied Chemistry (IUPAC), November2003. In the scope of this application, weight of a metal from thePeriodic Table, weight of a compound of a metal from the Periodic Table,weight of an element from the Periodic Table, or weight of a compound ofan element from the Periodic Table is calculated as the weight of metalor the weight of element. For example, if 0.1 grams of MoO₃ is used pergram of catalyst, the calculated weight of the molybdenum metal in thecatalyst is 0.067 grams per gram of catalyst.

“Phase transformation temperature” of a ferromagnetic material refers toa temperature or a temperature range during which the material undergoesa phase change (for example, from ferrite to austenite) that decreasesthe magnetic permeability of the ferromagnetic material. The reductionin magnetic permeability is similar to reduction in magneticpermeability due to the magnetic transition of the ferromagneticmaterial at the Curie temperature.

“Physical stability” refers to the ability of a formation fluid to notexhibit phase separation or flocculation during transportation of thefluid. Physical stability is determined by ASTM Method D7060.

“Pyrolysis” is the breaking of chemical bonds due to the application ofheat. For example, pyrolysis may include transforming a compound intoone or more other substances by heat alone. Heat may be transferred to asection of the formation to cause pyrolysis.

“Pyrolyzation fluids” or “pyrolysis products” refers to fluid producedsubstantially during pyrolysis of hydrocarbons. Fluid produced bypyrolysis reactions may mix with other fluids in a formation. Themixture would be considered pyrolyzation fluid or pyrolyzation product.As used herein, “pyrolysis zone” refers to a volume of a formation (forexample, a relatively permeable formation such as a tar sands formation)that is reacted or reacting to form a pyrolyzation fluid.

“Residue” refers to hydrocarbons that have a boiling point above 537° C.(1000° F.).

“Rich layers” in a hydrocarbon containing formation are relatively thinlayers (typically about 0.2 m to about 0.5 m thick). Rich layersgenerally have a richness of about 0.150 L/kg or greater. Some richlayers have a richness of about 0.170 L/kg or greater, of about 0.190L/kg or greater, or of about 0.210 L/kg or greater. Lean layers of theformation have a richness of about 0.100 L/kg or less and are generallythicker than rich layers. The richness and locations of layers aredetermined, for example, by coring and subsequent Fischer assay of thecore, density or neutron logging, or other logging methods. Rich layersmay have a lower initial thermal conductivity than other layers of theformation. Typically, rich layers have a thermal conductivity 1.5 timesto 3 times lower than the thermal conductivity of lean layers. Inaddition, rich layers have a higher thermal expansion coefficient thanlean layers of the formation.

“Smart well technology” or “smart wellbore” refers to wells thatincorporate downhole measurement and/or control. For injection wells,smart well technology may allow for controlled injection of fluid intothe formation in desired zones. For production wells, smart welltechnology may allow for controlled production of formation fluid fromselected zones. Some wells may include smart well technology that allowsfor formation fluid production from selected zones and simultaneous orstaggered solution injection into other zones. Smart well technology mayinclude fiber optic systems and control valves in the wellbore. A smartwellbore used for an in situ heat treatment process may be WestbayMultilevel Well System MP55 available from Westbay Instruments Inc.(Burnaby, British Columbia, Canada).

“Subsidence” is a downward movement of a portion of a formation relativeto an initial elevation of the surface.

“Sulfur compound content” refers to an amount of sulfur in an organiccompound. Sulfur content is as determined by ASTM Method D4294.

“Superposition of heat” refers to providing heat from two or more heatsources to a selected section of a formation such that the temperatureof the formation at least at one location between the heat sources isinfluenced by the heat sources.

“Synthesis gas” is a mixture including hydrogen and carbon monoxide.Additional components of synthesis gas may include water, carbondioxide, nitrogen, methane, and other gases. Synthesis gas may begenerated by a variety of processes and feedstocks. Synthesis gas may beused for synthesizing a wide range of compounds.

“TAN” refers to a total acid number expressed as milligrams (“mg”) ofKOH per gram (“g”) of sample. TAN is as determined by ASTM Method D3242.

“Tar” is a viscous hydrocarbon that generally has a viscosity greaterthan about 10,000 centipoise at 15° C. The specific gravity of targenerally is greater than 1.000. Tar may have an API gravity less than10°.

A “tar sands formation” is a formation in which hydrocarbons arepredominantly present in the form of heavy hydrocarbons and/or tarentrained in a mineral grain framework or other host lithology (forexample, sand or carbonate). Examples of tar sands formations includeformations such as the Athabasca formation, the Grosmont formation, andthe Peace River formation, all three in Alberta, Canada; and the Fajaformation in the Orinoco belt in Venezuela.

“Temperature limited heater” generally refers to a heater that regulatesheat output (for example, reduces heat output) above a specifiedtemperature without the use of external controls such as temperaturecontrollers, power regulators, rectifiers, or other devices. Temperaturelimited heaters may be AC (alternating current) or modulated (forexample, “chopped”) DC (direct current) powered electrical resistanceheaters.

“Thermally conductive fluid” includes fluid that has a higher thermalconductivity than air at standard temperature and pressure (STP) (0° C.and 101.325 kPa).

“Thermal conductivity” is a property of a material that describes therate at which heat flows, in steady state, between two surfaces of thematerial for a given temperature difference between the two surfaces.

“Thermal fracture” refers to fractures created in a formation caused byexpansion or contraction of a formation and/or fluids in the formation,which is in turn caused by increasing/decreasing the temperature of theformation and/or fluids in the formation, and/or byincreasing/decreasing a pressure of fluids in the formation due toheating.

“Thermal oxidation stability” refers to thermal oxidation stability of aliquid. Thermal oxidation stability is as determined by ASTM MethodD3241.

“Thickness” of a layer refers to the thickness of a cross section of thelayer, wherein the cross section is normal to a face of the layer.

“Time-varying current” refers to electrical current that produces skineffect electricity flow in a ferromagnetic conductor and has a magnitudethat varies with time. Time-varying current includes both alternatingcurrent (AC) and modulated direct current (DC).

“Triad” refers to a group of three items (for example, heaters,wellbores, or other objects) coupled together.

“Turndown ratio” for the temperature limited heater in which current isapplied directly to the heater is the ratio of the highest AC ormodulated DC resistance below the Curie temperature to the lowestresistance above the Curie temperature for a given current. Turndownratio for an inductive heater is the ratio of the highest heat outputbelow the Curie temperature to the lowest heat output above the Curietemperature for a given current applied to the heater.

A “u-shaped wellbore” refers to a wellbore that extends from a firstopening in the formation, through at least a portion of the formation,and out through a second opening in the formation. In this context, thewellbore may be only roughly in the shape of a “v” or “u”, with theunderstanding that the “legs” of the “u” do not need to be parallel toeach other, or perpendicular to the “bottom” of the “u” for the wellboreto be considered “u-shaped”.

“Upgrade” refers to increasing the quality of hydrocarbons. For example,upgrading heavy hydrocarbons may result in an increase in the APIgravity of the heavy hydrocarbons.

“Visbreaking” refers to the untangling of molecules in fluid during heattreatment and/or to the breaking of large molecules into smallermolecules during heat treatment, which results in a reduction of theviscosity of the fluid.

“Viscosity” refers to kinematic viscosity at 40° C. unless otherwisespecified. Viscosity is as determined by ASTM Method D445.

“VGO” or “vacuum gas oil” refers to hydrocarbons with a boiling rangedistribution between 343° C. and 538° C. at 0.101 MPa. VGO content isdetermined by ASTM Method D5307.

A “vug” is a cavity, void or large pore in a rock that is commonly linedwith mineral precipitates.

“Wax” refers to a low melting organic mixture, or a compound of highmolecular weight that is a solid at lower temperatures and a liquid athigher temperatures, and when in solid form can form a barrier to water.Examples of waxes include animal waxes, vegetable waxes, mineral waxes,petroleum waxes, and synthetic waxes.

The term “wellbore” refers to a hole in a formation made by drilling orinsertion of a conduit into the formation. A wellbore may have asubstantially circular cross section, or another cross-sectional shape.As used herein, the terms “well” and “opening,” when referring to anopening in the formation may be used interchangeably with the term“wellbore.”

A formation may be treated in various ways to produce many differentproducts. Different stages or processes may be used to treat theformation during an in situ heat treatment process. In some embodiments,one or more sections of the formation are solution mined to removesoluble minerals from the sections. Solution mining minerals may beperformed before, during, and/or after the in situ heat treatmentprocess. In some embodiments, the average temperature of one or moresections being solution mined may be maintained below about 120° C.

In some embodiments, one or more sections of the formation are heated toremove water from the sections and/or to remove methane and othervolatile hydrocarbons from the sections. In some embodiments, theaverage temperature may be raised from ambient temperature totemperatures below about 220° C. during removal of water and volatilehydrocarbons.

In some embodiments, one or more sections of the formation are heated totemperatures that allow for movement and/or visbreaking of hydrocarbonsin the formation. In some embodiments, the average temperature of one ormore sections of the formation are raised to mobilization temperaturesof hydrocarbons in the sections (for example, to temperatures rangingfrom 100° C. to 250° C., from 120° C. to 240° C., or from 150° C. to230° C.).

In some embodiments, one or more sections are heated to temperaturesthat allow for pyrolysis reactions in the formation. In someembodiments, the average temperature of one or more sections of theformation may be raised to pyrolysis temperatures of hydrocarbons in thesections (for example, temperatures ranging from 230° C. to 900° C.,from 240° C. to 400° C. or from 250° C. to 350° C.).

Heating the hydrocarbon containing formation with a plurality of heatsources may establish thermal gradients around the heat sources thatraise the temperature of hydrocarbons in the formation to desiredtemperatures at desired heating rates. The rate of temperature increasethrough mobilization temperature range and/or pyrolysis temperaturerange for desired products may affect the quality and quantity of theformation fluids produced from the hydrocarbon containing formation.Slowly raising the temperature of the formation through the mobilizationtemperature range and/or pyrolysis temperature range may allow for theproduction of high quality, high API gravity hydrocarbons from theformation. Slowly raising the temperature of the formation through themobilization temperature range and/or pyrolysis temperature range mayallow for the removal of a large amount of the hydrocarbons present inthe formation as hydrocarbon product.

In some in situ heat treatment embodiments, a portion of the formationis heated to a desired temperature instead of slowly heating thetemperature through a temperature range. In some embodiments, thedesired temperature is 300° C., 325° C., or 350° C. Other temperaturesmay be selected as the desired temperature.

Superposition of heat from heat sources allows the desired temperatureto be relatively quickly and efficiently established in the formation.Energy input into the formation from the heat sources may be adjusted tomaintain the temperature in the formation substantially at a desiredtemperature.

Mobilization and/or pyrolysis products may be produced from theformation through production wells. In some embodiments, the averagetemperature of one or more sections is raised to mobilizationtemperatures and hydrocarbons are produced from the production wells.The average temperature of one or more of the sections may be raised topyrolysis temperatures after production due to mobilization decreasesbelow a selected value. In some embodiments, the average temperature ofone or more sections may be raised to pyrolysis temperatures withoutsignificant production before reaching pyrolysis temperatures. Formationfluids including pyrolysis products may be produced through theproduction wells.

In some embodiments, the average temperature of one or more sections maybe raised to temperatures sufficient to allow synthesis gas productionafter mobilization and/or pyrolysis. In some embodiments, hydrocarbonsmay be raised to temperatures sufficient to allow synthesis gasproduction without significant production before reaching thetemperatures sufficient to allow synthesis gas production. For example,synthesis gas may be produced in a temperature range from about 400° C.to about 1200° C., about 500° C. to about 1100° C., or about 550° C. toabout 1000° C. A synthesis gas generating fluid (for example, steamand/or water) may be introduced into the sections to generate synthesisgas. Synthesis gas may be produced from production wells.

Solution mining, removal of volatile hydrocarbons and water, mobilizinghydrocarbons, pyrolyzing hydrocarbons, generating synthesis gas, and/orother processes may be performed during the in situ heat treatmentprocess. In some embodiments, some processes may be performed after thein situ heat treatment process. Such processes may include, but are notlimited to, recovering heat from treated sections, storing fluids (forexample, water and/or hydrocarbons) in previously treated sections,and/or sequestering carbon dioxide in previously treated sections.

FIG. 1 depicts a schematic view of an embodiment of a portion of the insitu heat treatment system for treating the hydrocarbon containingformation. The in situ heat treatment system may include barrier wells200. Barrier wells are used to form a barrier around a treatment area.The barrier inhibits fluid flow into and/or out of the treatment area.Barrier wells include, but are not limited to, dewatering wells, vacuumwells, capture wells, injection wells, grout wells, freeze wells, orcombinations thereof. In some embodiments, barrier wells 200 aredewatering wells. Dewatering wells may remove liquid water and/orinhibit liquid water from entering a portion of the formation to beheated, or to the formation being heated. In the embodiment depicted inFIG. 1, the barrier wells 200 are shown extending only along one side ofheat sources 202, but the barrier wells typically encircle all heatsources 202 used, or to be used, to heat a treatment area of theformation.

Heat sources 202 are placed in at least a portion of the formation. Heatsources 202 may include heaters such as insulated conductors,conductor-in-conduit heaters, surface burners, flameless distributedcombustors, and/or natural distributed combustors. Heat sources 202 mayalso include other types of heaters. Heat sources 202 provide heat to atleast a portion of the formation to heat hydrocarbons in the formation.Energy may be supplied to heat sources 202 through supply lines 204.Supply lines 204 may be structurally different depending on the type ofheat source or heat sources used to heat the formation. Supply lines 204for heat sources may transmit electricity for electric heaters, maytransport fuel for combustors, or may transport heat exchange fluid thatis circulated in the formation. In some embodiments, electricity for anin situ heat treatment process may be provided by a nuclear power plantor nuclear power plants. The use of nuclear power may allow forreduction or elimination of carbon dioxide emissions from the in situheat treatment process.

When the formation is heated, the heat input into the formation maycause expansion of the formation and geomechanical motion. The heatsources may be turned on before, at the same time, or during adewatering process. Computer simulations may model formation response toheating. The computer simulations may be used to develop a pattern andtime sequence for activating heat sources in the formation so thatgeomechanical motion of the formation does not adversely affect thefunctionality of heat sources, production wells, and other equipment inthe formation.

Heating the formation may cause an increase in permeability and/orporosity of the formation. Increases in permeability and/or porosity mayresult from a reduction of mass in the formation due to vaporization andremoval of water, removal of hydrocarbons, and/or creation of fractures.Fluid may flow more easily in the heated portion of the formationbecause of the increased permeability and/or porosity of the formation.Fluid in the heated portion of the formation may move a considerabledistance through the formation because of the increased permeabilityand/or porosity. The considerable distance may be over 1000 m dependingon various factors, such as permeability of the formation, properties ofthe fluid, temperature of the formation, and pressure gradient allowingmovement of the fluid. The ability of fluid to travel considerabledistance in the formation allows production wells 206 to be spacedrelatively far apart in the formation.

Production wells 206 are used to remove formation fluid from theformation. In some embodiments, production well 206 includes a heatsource. The heat source in the production well may heat one or moreportions of the formation at or near the production well. In some insitu heat treatment process embodiments, the amount of heat supplied tothe formation from the production well per meter of the production wellis less than the amount of heat applied to the formation from a heatsource that heats the formation per meter of the heat source. Heatapplied to the formation from the production well may increase formationpermeability adjacent to the production well by vaporizing and removingliquid phase fluid adjacent to the production well and/or by increasingthe permeability of the formation adjacent to the production well byformation of macro and/or micro fractures.

More than one heat source may be positioned in the production well. Aheat source in a lower portion of the production well may be turned offwhen superposition of heat from adjacent heat sources heats theformation sufficiently to counteract benefits provided by heating theformation with the production well. In some embodiments, the heat sourcein an upper portion of the production well may remain on after the heatsource in the lower portion of the production well is deactivated. Theheat source in the upper portion of the well may inhibit condensationand reflux of formation fluid.

In some embodiments, the heat source in production well 206 allows forvapor phase removal of formation fluids from the formation. Providingheating at or through the production well may: (1) inhibit condensationand/or refluxing of production fluid when such production fluid ismoving in the production well proximate the overburden, (2) increaseheat input into the formation, (3) increase production rate from theproduction well as compared to a production well without a heat source,(4) inhibit condensation of high carbon number compounds (C₆hydrocarbons and above) in the production well, and/or (5) increaseformation permeability at or proximate the production well.

Subsurface pressure in the formation may correspond to the fluidpressure generated in the formation. As temperatures in the heatedportion of the formation increase, the pressure in the heated portionmay increase as a result of thermal expansion of in situ fluids,increased fluid generation and vaporization of water. Controlling rateof fluid removal from the formation may allow for control of pressure inthe formation. Pressure in the formation may be determined at a numberof different locations, such as near or at production wells, near or atheat sources, or at monitor wells.

In some hydrocarbon containing formations, production of hydrocarbonsfrom the formation is inhibited until at least some hydrocarbons in theformation have been mobilized and/or pyrolyzed. Formation fluid may beproduced from the formation when the formation fluid is of a selectedquality. In some embodiments, the selected quality includes an APIgravity of at least about 20°, 30°, or 40°. Inhibiting production untilat least some hydrocarbons are mobilized and/or pyrolyzed may increaseconversion of heavy hydrocarbons to light hydrocarbons. Inhibitinginitial production may minimize the production of heavy hydrocarbonsfrom the formation. Production of substantial amounts of heavyhydrocarbons may require expensive equipment and/or reduce the life ofproduction equipment.

In some hydrocarbon containing formations, hydrocarbons in the formationmay be heated to mobilization and/or pyrolysis temperatures beforesubstantial permeability has been generated in the heated portion of theformation. An initial lack of permeability may inhibit the transport ofgenerated fluids to production wells 206. During initial heating, fluidpressure in the formation may increase proximate heat sources 202. Theincreased fluid pressure may be released, monitored, altered, and/orcontrolled through one or more heat sources 202. For example, selectedheat sources 202 or separate pressure relief wells may include pressurerelief valves that allow for removal of some fluid from the formation.

In some embodiments, pressure generated by expansion of mobilizedfluids, pyrolysis fluids or other fluids generated in the formation maybe allowed to increase although an open path to production wells 206 orany other pressure sink may not yet exist in the formation. The fluidpressure may be allowed to increase towards a lithostatic pressure.Fractures in the hydrocarbon containing formation may form when thefluid approaches the lithostatic pressure. For example, fractures mayform from heat sources 202 to production wells 206 in the heated portionof the formation. The generation of fractures in the heated portion mayrelieve some of the pressure in the portion. Pressure in the formationmay have to be maintained below a selected pressure to inhibit unwantedproduction, fracturing of the overburden or underburden, and/or cokingof hydrocarbons in the formation.

After mobilization and/or pyrolysis temperatures are reached andproduction from the formation is allowed, pressure in the formation maybe varied to alter and/or control a composition of formation fluidproduced, to control a percentage of condensable fluid as compared tonon-condensable fluid in the formation fluid, and/or to control an APIgravity of formation fluid being produced. For example, decreasingpressure may result in production of a larger condensable fluidcomponent. The condensable fluid component may contain a largerpercentage of olefins.

In some in situ heat treatment process embodiments, pressure in theformation may be maintained high enough to promote production offormation fluid with an API gravity of greater than 20°. Maintainingincreased pressure in the formation may inhibit formation subsidenceduring in situ heat treatment. Maintaining increased pressure may reduceor eliminate the need to compress formation fluids at the surface totransport the fluids in collection conduits to treatment facilities.

Maintaining increased pressure in a heated portion of the formation maysurprisingly allow for production of large quantities of hydrocarbons ofincreased quality and of relatively low molecular weight. Pressure maybe maintained so that formation fluid produced has a minimal amount ofcompounds above a selected carbon number. The selected carbon number maybe at most 25, at most 20, at most 12, or at most 8. Some high carbonnumber compounds may be entrained in vapor in the formation and may beremoved from the formation with the vapor. Maintaining increasedpressure in the formation may inhibit entrainment of high carbon numbercompounds and/or multi-ring hydrocarbon compounds in the vapor. Highcarbon number compounds and/or multi-ring hydrocarbon compounds mayremain in a liquid phase in the formation for significant time periods.The significant time periods may provide sufficient time for thecompounds to pyrolyze to form lower carbon number compounds.

Generation of relatively low molecular weight hydrocarbons is believedto be due, in part, to autogenous generation and reaction of hydrogen ina portion of the hydrocarbon containing formation. For example,maintaining an increased pressure may force hydrogen generated duringpyrolysis into the liquid phase within the formation. Heating theportion to a temperature in a pyrolysis temperature range may pyrolyzehydrocarbons in the formation to generate liquid phase pyrolyzationfluids. The generated liquid phase pyrolyzation fluids components mayinclude double bonds and/or radicals. Hydrogen (H₂) in the liquid phasemay reduce double bonds of the generated pyrolyzation fluids, therebyreducing a potential for polymerization or formation of long chaincompounds from the generated pyrolyzation fluids. In addition, H₂ mayalso neutralize radicals in the generated pyrolyzation fluids. H₂ in theliquid phase may inhibit the generated pyrolyzation fluids from reactingwith each other and/or with other compounds in the formation.

Formation fluid produced from production wells 206 may be transportedthrough collection piping 208 to treatment facilities 210. Formationfluids may also be produced from heat sources 202. For example, fluidmay be produced from heat sources 202 to control pressure in theformation adjacent to the heat sources. Fluid produced from heat sources202 may be transported through tubing or piping to collection piping 208or the produced fluid may be transported through tubing or pipingdirectly to treatment facilities 210. Treatment facilities 210 mayinclude separation units, reaction units, upgrading units, fuel cells,turbines, storage vessels, and/or other systems and units for processingproduced formation fluids. The treatment facilities may formtransportation fuel from at least a portion of the hydrocarbons producedfrom the formation. In some embodiments, the transportation fuel may bejet fuel, such as JP-8.

Formation fluid may be hot when produced from the formation through theproduction wells. Hot formation fluid may be produced during solutionmining processes and/or during in situ heat treatment processes. In someembodiments, electricity may be generated using the heat of the fluidproduced from the formation. Also, heat recovered from the formationafter the in situ process may be used to generate electricity. Thegenerated electricity may be used to supply power to the in situ heattreatment process. For example, the electricity may be used to powerheaters, or to power a refrigeration system for forming or maintaining alow temperature barrier. Electricity may be generated using a Kalinacycle, Rankine cycle or other thermodynamic cycle. In some embodiments,the working fluid for the cycle used to generate electricity is aquaammonia.

FIGS. 2-8 depict schematics representation of systems for producingcrude products and/or commercial products from the in situ heattreatment process liquid stream and/or the in situ heat treatmentprocess gas stream. As shown in FIGS. 2, 7 and 8, formation fluid 212enters fluid separation unit 214 and is separated into in situ heattreatment process liquid stream 216, in situ heat treatment process gas218 and aqueous stream 220. In some embodiments, liquid stream 216 maybe transported to other processing units and/or facilities.

Formation fluid 212 enters fluid separation unit 214 and is separatedinto in situ heat treatment process liquid stream 216, in situ heattreatment process gas 218, and aqueous stream 220. Liquid stream 216 maybe transported to other processing units and/or facilities. In someembodiments, fluid separation unit 214 includes a quench zone.

In situ heat treatment process gas 218 may enter gas separation unit 222to separate gas hydrocarbon stream 224 from the in situ heat treatmentprocess gas. In some embodiments, the gas separation unit is a rectifiedadsorption and high pressure fractionation unit. Gas hydrocarbon stream224 includes hydrocarbons having a carbon number of at least 3.

In some embodiments, fluid separation unit 214 includes a quench zone.As produced formation fluid enters the quench zone, quenching fluid suchas water, nonpotable water, hydrocarbon diluent, and/or other componentsmay be added to the formation fluid to quench and/or cool the formationfluid to a temperature suitable for handling in downstream processingequipment. Quenching the formation fluid may inhibit formation ofcompounds that contribute to physical and/or chemical instability of thefluid (for example, inhibit formation of compounds that may precipitatefrom solution, contribute to corrosion, and/or fouling of downstreamequipment and/or piping). The quenching fluid may be introduced into theformation fluid as a spray and/or a liquid stream. In some embodiments,the formation fluid is introduced into the quenching fluid. In someembodiments, the formation fluid is cooled by passing the fluid througha heat exchanger to remove some heat from the formation fluid. Thequench fluid may be added to the cooled formation fluid when thetemperature of the formation fluid is near or at the dew point of thequench fluid. Quenching the formation fluid near or at the dew point ofthe quench fluid may enhance solubilization of salts that may causechemical and/or physical instability of the quenched fluid (for example,ammonium salts). In some embodiments, an amount of water used in thequench is minimal so that salts of inorganic compounds and/or othercomponents do not separate from the mixture. In separation unit 214, atleast a portion of the quench fluid may be separated from the quenchmixture and recycled to the quench zone with a minimal amount oftreatment. Heat produced from the quench may be captured and used inother facilities. In some embodiments, vapor may be produced during thequench. The produced vapor may be sent to gas separation unit 222 and/orsent to other facilities for processing.

In situ heat treatment process gas 218 may enter gas separation unit 222to separate gas hydrocarbon stream 224 from the in situ heat treatmentprocess gas. In some embodiments, the gas separation unit is a rectifiedadsorption and high pressure fractionation unit. Gas hydrocarbon stream224 includes hydrocarbons having a carbon number of at least 3. In gasseparation unit 222, treatment of in situ heat conversion treatment gas218 removes sulfur compounds, carbon dioxide, and/or hydrogen to producegas hydrocarbon stream 224. In some embodiments, in situ heat treatmentprocess gas 218 includes about 20 vol % hydrogen, about 30% methane,about 12% carbon dioxide, about 14 vol % C₂ hydrocarbons, about 5 vol %hydrogen sulfide, about 10 vol % C₃ hydrocarbons, about 7 vol % C₄hydrocarbons, about 2 vol % C₅ hydrocarbons, and mixtures thereof, withthe balance being heavier hydrocarbons, water, ammonia, COS, thiols andthiophenes.

Gas separation unit 222 may include a physical treatment system and/or achemical treatment system. The physical treatment system may include,but is not limited to, a membrane unit, a pressure swing adsorptionunit, a liquid absorption unit, and/or a cryogenic unit. The chemicaltreatment system may include units that use amines (for example,diethanolamine or di-isopropanolamine), zinc oxide, sulfolane, water, ormixtures thereof in the treatment process. In some embodiments, gasseparation unit 222 uses a Sulfinol gas treatment process for removal ofsulfur compounds. Carbon dioxide may be removed using Catacarb®(Catacarb, Overland Park, Kans., U.S.A.) and/or Benfield (UOP, DesPlaines, Ill., U.S.A.) gas treatment processes. In some embodiments, thegas separation unit is a rectified adsorption and high pressurefractionation unit. In some embodiments, in situ heat treatment processgas is treated to remove at least 50%, at least 60%, at least 70%, atleast 80% or at least 90% by volume of ammonia present in the gasstream.

In situ heat treatment process gas 218 may include one or more carbonoxides and sulfur compounds that render the in situ heat treatmentprocess gas unacceptable for sale, transportation, and/or use as a fuel.The in situ heat treatment process gas 218 may be processed as describedherein to produce a gas stream acceptable for sale, transportation,and/or use as a fuel. It would be advantageous to separate the in situtreatment process gas 218 at the treatment site to produce streamsuseable as energy sources to lower overall energy costs. For example,streams containing hydrocarbons and/or hydrogen may be used as fuel forburners and/or process equipment. Streams containing sulfur compoundsmay be used as fuel for burners. Streams containing one or more carbonoxides and/or hydrocarbons may be used to form barriers around atreatment site. Streams containing hydrocarbons having a carbon numberof at most 2 may be provided to ammonia processing facilities and/orbarrier well systems. In situ heat treatment process gas 218 may includea sufficient amount of hydrogen such that the freezing point of carbondioxide is depressed. Depression of the freezing point of carbon dioxidemay allow cryogenic separation of hydrogen and/or hydrocarbons from thecarbon dioxide using distillation methods instead of removing the carbondioxide by cryogenic precipitation methods. In some embodiments, thefreezing point of carbon dioxide may be depressed by adjusting theconcentration of molecular hydrogen and/or addition of heavyhydrocarbons to the process gas stream.

As shown in FIG. 2, in situ heat treatment process gas 218 may entercompressor 232 of gas separation unit 222 to form compressed gas stream234 and heavy stream 236. Heavy stream 236 may be transported to one ormore liquid separation units for further processing. Compressor 232 maybe any compressor suitable for compressing gas. In certain embodiments,compressor 232 is a multistage compressor (for example 2 to 3 compressortrains) having an outlet pressure of about 40 bars. In some embodiments,compressed gas stream 234 may include at least 1 vol % carbon dioxide,at least 10 vol % hydrogen, at least 1 vol % hydrogen sulfide, at least50 vol % of hydrocarbons having a carbon number of at most 4, ormixtures thereof. Compression of in situ heat treatment process gas 218removes hydrocarbons having a carbon number of at least 5 and water.Removal of water and hydrocarbons having a carbon number of at least 5from the in situ process gas allows compressed gas stream 234 to betreated cryogenically. Cryogenic treatment of compressed gas stream 234having small amounts of high boiling materials may be done moreefficiently. In certain embodiments, compressed gas stream 234 is driedby passing the gas through a water adsorption unit. In some embodiments,compressing in situ heat treatment process gas 218 is not necessary.

As shown in FIGS. 2 through 6, gas separation unit 222 includes one ormore cryogenic units or zones. Cryogenic units described herein mayinclude one or more theoretical distillation stages. In FIGS. 2 through6, one or more heat exchangers may be positioned prior to or aftercryogenic units and/or separation units described herein to assist inremoving and/or adding heat to one or more streams described herein. Atleast a portion or all of the separated hydrocarbons streams and/or theseparated carbon dioxides streams may be transported to the heatexchangers. Heat integration from one or more heat exchangers to variousunits or zones may be applied to improve the energy efficiency of theprocess.

In some embodiments, theoretical distillation stages may include from 1to about 100 stages, from about 5 to about 50 theoretical distillationstages, or from about 10 to about 40 theoretical distillation stages.Zones of the cryogenic units may be cooled to temperatures ranging fromabout −110° C. to about 0° C. For example, zone 1 (top theoreticaldistillation stage) in a cryogenic unit is cooled to about −110° C.,zone 5 (theoretical distillation stage 5) is cooled to about −25° C.,and zone 10 (theoretical distillation stage 10) is cooled to about −1°C. Total pressures in cryogenic units may range from about 1 bar toabout 50 bar, from about 5 bar to about 40 bar, or from about 10 bar toabout 30 bar. Operating the cryogenic zones and/or units at thesetemperatures and pressures may allow separation of hydrogen sulfideand/or carbon dioxide from hydrocarbons in the process stream. Cryogenicunits described herein may include condenser recycle conduits 238 andreboiler recycle conduits 240. Condenser recycle conduits 238 allowrecycle of the cooled condensed gases so that the feed may be cooled asit enters the cryogenic units. Condenser liquid recycle or reflux mayimprove fractionation effectiveness. Temperatures in condensation loopsmay range from about −110° C. to about −1° C., from about −90° C. toabout −5° C., or from about −80° C. to about −10° C. Temperatures inreboiler loops may range from about 25° C. to about 200° C., from about50° C. to about 150° C., or from about 75° C. to about 100° C. Reboilerrecycle conduits 240 allow recycle of the stream exiting the cryogenicunit to heat the feed as it enters the cryogenic unit. Recycle of thecooled and/or warmed separated stream may enhance energy efficiency ofthe cryogenic unit.

As shown in FIG. 2, compressed gas stream 234 enters methane/hydrogencryogenic unit 242. In cryogenic unit 242, compressed gas stream 234 maybe separated into a methane/molecular hydrogen gas stream 244 and abottoms stream 246. Bottoms stream 246 may include, but is not limitedto carbon dioxide, hydrogen sulfide, and hydrocarbons having a carbonnumber of at least 2. A majority of methane/hydrogen stream 244 ismethane and molecular hydrogen. Methane/hydrogen stream 244 may includea minimal amount of C₂ hydrocarbons and carbon dioxide. For example,methane/hydrogen stream 244 may include about 1 vol % C₂ hydrocarbonsand about 1 vol % carbon dioxide. In some embodiments, themethane/hydrogen stream is recycled to one or more heat exchangerspositioned prior to cryogenic unit 242. In some embodiments, themethane/hydrogen stream is used as a fuel for downhole burners and/or anenergy source for surface facilities.

In some embodiments, cryogenic unit 242 may include one distillationcolumn having 1 to about 30 theoretical distillation stages, about 5 toabout 25 theoretical distillation stages, or about 10 to about 20theoretical distillation stages. Zones of cryogenic unit 242 may becooled to temperatures ranging from about −150° C. to about 10° C. Forexample, zone 1 (top theoretical distillation stage) is cooled to about−138° C., zone 5 (theoretical distillation stage 5) is cooled to about−25° C., and zone 10° C. (theoretical distillation stage 10) is cooledto at about −1° C. At temperatures lower than −79° C. cryogenicseparation of the carbon dioxide from other gases may be difficult dueto the freezing point of carbon dioxide. In some embodiments, cryogenicunit 242 includes about 20 theoretical distillation stages. Cryogenicunit 242 may be operated at a pressure of 40 bar with distillationtemperatures ranging from about −45° C. to about −94° C.

Compressed gas stream 234 may include sufficient hydrogen and/orhydrocarbons having a carbon number of at least 1 to inhibit solidcarbon dioxide formation. For example, in situ heat treatment processgas 218 may include from about 30 vol % to about 40 vol % of hydrogen,from about 50 vol % to 60 vol % of hydrocarbons having a carbon numberfrom 1 to 2, from about 0.1 vol % to about 15 vol % of carbon dioxidewith the balance being other gases such as, but not limited to, carbonmonoxide, nitrogen, and hydrogen sulfide. Inhibiting solid carbondioxide formation may allow for better separation of gases and/or lessfouling of the cryogenic unit. In some embodiments, hydrocarbons havinga carbon number of at least five may be added to cryogenic unit 242 toinhibit formation of solid carbon dioxide. The resultingmethane/hydrogen gas stream 244 may be used as an energy source. Forexample, methane/hydrogen gas stream 244 may be transported to surfacefacilities and burned to generate electricity.

As shown in FIG. 2, bottoms stream 246 enters cryogenic separation unit248. In cryogenic separation unit 248, bottoms stream 246 is separatedinto C₃ hydrocarbons stream 250 and gas stream 252. C₃ hydrocarbonsstream 250 may include hydrocarbons having a carbon number of at least3. C₃ hydrocarbons stream 250 may be a liquid and/or a gas depending onthe separation conditions. In some embodiments, C₃ hydrocarbons stream250 includes at least 50 vol %, at least 70 vol % or at least 90 vol %of C₃ hydrocarbons. C₃ hydrocarbons stream 250 may include at most 1 ppmof carbon dioxide, and about 0.1 vol % of hydrogen sulfide. In someembodiments, C₃ hydrocarbons stream 250 includes hydrocarbons having acarbon number of at least 2 and organosulfur compounds. In someembodiments, C₃ hydrocarbons stream 250 includes hydrocarbons having acarbon number from 3 to 5. In some embodiments, C₃ hydrocarbons stream250 includes hydrogen sulfide in quantities sufficient to requiretreatment of the stream to remove the hydrogen sulfide. In someembodiments, C₃ hydrocarbons gas stream 250 is suitable fortransportation and/or use as an energy source without further treatment.In some embodiments, C₃ hydrocarbons stream 250 is used as an energysource for in situ heat treatment processes.

Gas stream 252 may include hydrocarbons having a carbon number of atleast 2, carbon oxides and sulfur compounds. In some embodiments, gasstream 252 includes hydrocarbons having a carbon number of at most 2. Aportion of gas stream 252 may be transported to one or more portions ofthe formation and sequestered. In some embodiments, all of gas stream252 is sequestered in one or more portions of the formation. In someembodiments, a portion of gas stream 252 enters cryogenic unit 256. Incryogenic unit 256, gas stream 252 is separated into C₂hydrocarbons/carbon dioxide stream 258 and hydrogen sulfide stream 260.In some embodiments, C₂ hydrocarbons/carbon dioxide stream 258 includesat most 0.5 vol % of hydrogen sulfide.

In some embodiments, hydrogen sulfide stream 260 includes about 0.01 vol% to about 5 vol % of C₃ hydrocarbons. In some embodiments, hydrogensulfide stream 260 includes hydrogen sulfide, carbon dioxide, C₃hydrocarbons, or mixtures thereof. For example, hydrogen sulfide stream260 includes, about 32 vol % of hydrogen sulfide, 67 vol % carbondioxide, and 1 vol % C₃ hydrocarbons. In some embodiments, hydrogensulfide stream 260 is used as an energy source for an in situ heattreatment process and/or sent to a Claus plant for further treatment.

A portion or all of C₂ hydrocarbons/carbon dioxide stream 258 may enterseparation unit 262. In separation unit 262, C₂ hydrocarbons/carbondioxide stream 258 is separated into C₂ hydrocarbons stream 264 andcarbon dioxide stream 266. Separation of C₂ hydrocarbons from carbondioxide is performed using separation methods known in the art, forexample, pressure swing adsorption units, and/or extractive distillationunits. In some embodiments, C₂ hydrocarbons are separated from carbondioxide using extractive distillation methods. For example, hydrocarbonshaving a carbon number from 3 to 8 may be added to separation unit 262.Addition of a higher carbon number hydrocarbon solvent allows C₂hydrocarbons to be extracted from the carbon dioxide. C₂ hydrocarbonsare then separated from the higher carbon number hydrocarbons usingdistillation techniques. In some embodiments, C₂ hydrocarbons stream 264is transported to other process facilities and/or used as an energysource. For example, C₂ hydrocarbons stream 264 may be provided to oneor more ammonia processing facilities. Carbon dioxide stream 266 may besequestered in one or more portions of the formation. In someembodiments, carbon dioxide stream 266 is provided to one or morebarrier well systems. In some embodiments, carbon dioxide stream 266contains at most 0.005 grams of non-carbon dioxide compounds per gram ofcarbon dioxide stream. In some embodiments, carbon dioxide stream 266 ismixed with one or more oxidant sources supplied to one or more downholeburners.

In some embodiments, a portion or all of C₂ hydrocarbons/carbon dioxidestream 258 is sequestered and/or transported to other facilities and/orprovided to one or more barrier well systems. In some embodiments, aportion or all of C₂ hydrocarbons/carbon dioxide stream 258 is mixedwith one or more oxidant sources supplied to one or more downholeburners.

As depicted in FIG. 3, bottoms stream 246 enters cryogenic separationunit 270. In cryogenic separation unit 270, bottoms stream 246 may beseparated into C₂ hydrocarbons/carbon dioxide stream 258 and hydrogensulfide/hydrocarbon gas stream 272. In some embodiments, C₂hydrocarbons/carbon dioxide stream 258 contains hydrogen sulfide.Hydrogen sulfide/hydrocarbon gas stream 272 may include hydrocarbonshaving a carbon number of at least 3.

In some embodiments, a portion or all of C₂ hydrocarbons/carbon dioxidestream 258 are transported via conduit 268 to other processes and/or toone or more portions of the formation to be sequestered. In someembodiments, a portion or all of C₂ hydrocarbons/carbon dioxide stream258 are treated in separation unit 262. Separation unit 262 is describedabove with reference to FIG. 2.

Hydrogen sulfide/hydrocarbon gas stream 272 may enter cryogenicseparation unit 274. In cryogenic separation unit 274, hydrogen sulfidemay be separated from hydrocarbons having a carbon number of at least 3to produce hydrogen sulfide stream 260 and C₃ hydrocarbons stream 250.Hydrogen sulfide stream 260 may include, but is not limited to, hydrogensulfide, C₃ hydrocarbons, carbon dioxide, or mixtures thereof. In someembodiments, hydrogen sulfide stream 260 may contain from about 20 vol %to about 80 vol % of hydrogen sulfide, from about 4 vol % to about 18vol % of propane and from about 2 vol % to about 70 vol % of carbondioxide. In some embodiments, hydrogen sulfide stream 260 is burned toproduce SO_(x). The SO_(x) may be sequestered and/or treated using knowntechniques in the art.

In some embodiments, C₃ hydrocarbons stream 250 includes a minimalamount of hydrogen sulfide and carbon dioxide. For example, C₃hydrocarbons stream 250 may include about 99.6 vol % of hydrocarbonshaving a carbon number of at least 3, about 0.4 vol % of hydrogensulfide and at most 1 ppm of carbon dioxide. In some embodiments, C₃hydrocarbons stream 250 is transported to other processing facilities asan energy source. In some embodiments, C₃ hydrocarbons stream 250 needsno further treatment.

As depicted in FIG. 4, bottoms stream 246 may enter cryogenic separationunit 276. In cryogenic separation unit 276, bottoms stream 246 may beseparated into C₂ hydrocarbons/hydrogen sulfide/carbon dioxide gasstream 278 and hydrogen sulfide/hydrocarbon gas stream 272. In someembodiments, cryogenic separation unit 276 includes 45 theoreticaldistillation stages. A top zone (top theoretical distillation stage) ofcryogenic separation unit 276 may be operated at a temperature of −31°C. and a pressure of about 20 bar.

A portion or all of C₂ hydrocarbons/hydrogen sulfide/carbon dioxide gasstream 278 and hydrocarbon stream 280 may enter cryogenic separationunit 282. Hydrocarbon stream 280 may be any hydrocarbon stream suitablefor use in a cryogenic extractive distillation system. In someembodiments, hydrocarbon stream 280 is n-hexane. In cryogenic separationunit 282, C₂ hydrocarbons/hydrogen sulfide/carbon dioxide gas stream 278is separated into carbon dioxide stream 266 and additionalhydrocarbon/hydrogen sulfide stream 284. In some embodiments, cryogenicseparation unit 282 includes 40 theoretical distillation stages.Cryogenic separation unit 282 may be operated at a temperature of about−19° C. and a pressure of about 20 bar.

In some embodiments, carbon dioxide stream 266 includes about 2.5 vol %of hydrocarbons having a carbon number of at most 2. In someembodiments, carbon dioxide stream 266 may be mixed with diluent fluidand/or oxidant for downhole burners, may be used as a carrier fluid foroxidizing fluid for downhole burners, may be used as a drive fluid forproducing hydrocarbons, may be vented, may be used in barrier wells,and/or may be sequestered. In some embodiments carbon dioxide stream 266is solidified.

Additional hydrocarbon/hydrogen sulfide stream 284 may be in the gas orliquid phase depending on the composition of the stream and/or theprocess conditions. Additional hydrocarbon/hydrogen sulfide stream 284may enter cryogenic separation unit 286. Additional hydrocarbon/hydrogensulfide stream 284 may include solvent hydrocarbons, C₂ hydrocarbons andhydrogen sulfide. In cryogenic separation unit 286, additionalhydrocarbon/hydrogen sulfide stream 284 may be separated into C₂hydrocarbons/hydrogen sulfide gas stream 288 and hydrocarbon stream 290.Hydrocarbon stream 290 may contain hydrocarbons having a carbon numberof at least 3. Hydrocarbon stream 290 may be a liquid or gas dependingon the composition of the stream and/or process conditions. In someembodiments, separation unit 286 includes 20 theoretical distillationstages. Cryogenic separation unit 286 may be operated at temperatures ofabout −16° C. and a pressure of about 10 bar.

Hydrogen sulfide/hydrocarbon gas stream 272 may enter cryogenicseparation unit 274. In cryogenic separation unit 274, hydrogen sulfidemay be separated from hydrocarbons having a carbon number of at least 3to produce hydrogen sulfide stream 260 and C₃ hydrocarbons stream 250.Hydrogen sulfide stream 260 may include, but is not limited to, hydrogensulfide, C₂ hydrocarbons, C₃ hydrocarbons, carbon dioxide, or mixturesthereof. In some embodiments, hydrogen sulfide stream 260 contains about31 vol % hydrogen sulfide with the balance being C₂ and C₃ hydrocarbons.Hydrogen sulfide stream 260 may be burned to produce SO_(x). The SO_(x)may be sequestered and/or treated using known techniques in the art.

In some embodiments, cryogenic separation unit 274 includes about 40theoretical distillation stages. Temperatures in cryogenic separationunit 274 may range from about 0° C. to about 10° C. Pressure incryogenic separation unit 274 may be about 20 bar.

C₃ hydrocarbons stream 250 may be a gas or liquid stream depending onthe composition of the stream and/or process conditions. C₃ hydrocarbonsstream 250 may include a minimal amount of hydrogen sulfide and carbondioxide. In some embodiments, C₃ hydrocarbons stream 250 includes about50 ppm of hydrogen sulfide. In some embodiments, C₃ hydrocarbons stream250 is transported to other processing facilities as an energy source.In some embodiments, hydrocarbons stream C₃ hydrocarbon stream 250 needsno further treatment.

As depicted in FIG. 5, compressed gas stream 234 may be treated using amodified Ryan/Holmes type process to recover the carbon dioxide from thecompressed gas stream. Compressed gas stream 234 enters cryogenicseparation unit 292. In some embodiments cryogenic separation unit 292includes 40 theoretical distillation stages. Cryogenic separation unit292 may be operated at a temperature ranging from about 60° C. to about−56° C. and a pressure of about 30 bar. In cryogenic separation unit292, compressed gas stream 234 may be separated into methane/carbondioxide gas stream 294 and hydrocarbon/hydrogen sulfide stream 296.

Methane/carbon dioxide gas stream 294 may include hydrocarbons having acarbon number of at most 2 and carbon dioxide. Methane/carbon dioxidegas stream 294 may be compressed in compressor 298 and enter cryogenicseparation unit 300. In cryogenic separation unit 300, methane/carbondioxide gas stream 294 is separated into carbon dioxide stream 266 andmethane stream 244. In some embodiments, cryogenic separation unit 300includes 20 theoretical distillation stages. Temperatures in cryogenicseparation unit 300 may range from about −56° C. to about −96° C. at apressure of about 45 bar.

Carbon dioxide stream 266 may include some hydrogen sulfide. Forexample, carbon dioxide stream 266 may include about 80 ppm of hydrogensulfide. At least a portion of carbon dioxide stream 266 may be used asa heat exchange medium in heat exchanger 302. In some embodiments, atleast a portion of carbon dioxide stream 266 is sequestered in theformation and/or at least a portion of the carbon dioxide stream is usedas a diluent in downhole oxidizer assemblies.

Hydrocarbon/hydrogen sulfide stream 296 may include hydrocarbons havinga carbon number of at least 2 and hydrogen sulfide. Hydrocarbon/hydrogensulfide stream 296 may be a gas or liquid stream depending on thehydrocarbon content of the stream and/or process conditions.Hydrocarbon/hydrogen sulfide stream 296 may pass through heat exchanger302 and enter separation unit 304. In separation unit 304,hydrocarbon/hydrogen sulfide stream 296 may be separated intohydrocarbon stream 306 and hydrogen sulfide stream 260. In someembodiments, separation unit 304 includes 30 theoretical distillationstages. Temperatures in separation unit 304 may range from about 60° C.to about 27° C. at a pressure of about 10 bar.

Hydrocarbon stream 306 may include hydrocarbons having a carbon numberof at least 3. Hydrocarbon stream 306 may include some hydrocarbonshaving a carbon number greater than 5. Hydrocarbon stream 306 mayinclude hydrocarbons having a carbon number of at most 5. In someembodiments, hydrocarbon stream 306 includes 10 vol % n-butanes and 85vol % hydrocarbons having a carbon number of 5. At least a portion ofhydrocarbon stream 306 may be recycled to cryogenic separation unit 292to maintain a ratio of about 1.4:1 of hydrocarbons to compressed gasstream 234.

Hydrogen sulfide stream 260 may include hydrogen sulfide, C₂hydrocarbons, and some carbon dioxide. In some embodiments, hydrogensulfide stream 260 includes about 13 vol % hydrogen sulfide, about 0.8vol % carbon dioxide with the balance being C₂ hydrocarbons. At least aportion of the hydrogen sulfide stream 260 may be burned as an energysource. In some embodiments, hydrogen sulfide stream 260 is used as afuel source in downhole burners.

In some embodiments, substantial removal of all the hydrogen sulfidefrom the C₂ hydrocarbons is desired. C₂ hydrocarbons may be used as anenergy source in surface facilities. Recovery of C₂ hydrocarbons mayenhance the energy efficiency of the process. Separation of hydrogensulfide from C₂ hydrocarbons may be difficult because C₂ hydrocarbonsboil at approximately the same temperature as a hydrogen sulfide/C₂hydrocarbons mixture. Addition of higher molecular weight (higherboiling) hydrocarbons does not enable the separation between hydrogensulfide and C₂ hydrocarbons as the addition of higher molecular weighthydrocarbons decreases the volatility of the C₂ hydrocarbons. It hasbeen advantageously found that the addition of carbon dioxide to thehydrogen sulfide/C₂ hydrocarbons mixture allows separation of hydrogensulfide from the C₂ hydrocarbons.

As shown in FIG. 6, bottoms stream 246 and carbon dioxide stream 314enter cryogenic separation unit 316. In some embodiments, the carbondioxide stream is added to the bottom stream prior to entering thecryogenic separation unit. In cryogenic separation unit 316, bottomsstream 246 may be separated into C₂ hydrocarbons/carbon dioxide gasstream 258 and hydrogen sulfide/hydrocarbon stream 318 by addition ofsufficient carbon dioxide to form a C₂ hydrocarbons/carbon dioxideazeotrope (for example, a C₂ hydrocarbons/carbon dioxide volume ratio of0.17:1 may be used). The C₂ hydrocarbons/carbon dioxide azeotrope has aboiling point lower than the boiling point of C₂ hydrocarbons. Forexample, the C₂ hydrocarbons/carbon dioxide azeotrope, where the C₂hydrocarbons are ethane, has a boiling point that is 14° C. lower thanC₂ boiling point at 10 bar, and a boiling point that is 22° C. lowerthan the C₂ boiling point at 40 bar. Use of a C₂ hydrocarbons/carbondioxide azeotrope allows formation of a C₂ hydrocarbons/carbon dioxidestream having a minimal amount of hydrogen sulfide (for example, a C₂hydrocarbons/carbon dioxide stream having at most 30 ppm, at most 25ppm, at most 20 ppm, or at most 10 ppm of hydrogen sulfide). In someembodiments, cryogenic separation unit 316 includes 40 theoreticaldistillation stages and may be operated at a pressure of about 10 bar.

At least a portion of C₂ hydrocarbons/carbon dioxide stream 258 andhydrocarbon recovery stream 320 may enter separation unit 262.Hydrocarbon recovery stream 320 may include hydrocarbons having a carbonnumber ranging from 4 to 7. In separation unit 262, contact of C₂hydrocarbons/carbon dioxide stream 258 with hydrocarbon recovery stream320 allows for separation of hydrocarbons from the C₂hydrocarbons/carbon dioxide stream to form separated carbon dioxidestream 266 and C₂ rich hydrocarbon stream 322. For example, ahydrocarbon recovery stream to C₂ hydrocarbons/carbon dioxide streamratio of 1.25 to 1 may effectively extract all the hydrocarbons from thecarbon dioxide. The ratio of hydrocarbon recovery stream to C₂hydrocarbons/carbon dioxide stream may depend on the relativeconcentrations of C₂ hydrocarbons and carbon dioxide in the C₂hydrocarbons/carbon dioxide stream. Separated carbon dioxide stream 266may be sequestered in the formation, used as a drive fluid, recycled tocryogenic separation unit 316, or used as a cooling fluid in otherprocesses.

C₂ rich hydrocarbon stream 322 may enter hydrocarbon recovery unit 324.In hydrocarbon recovery unit 324, C₂ rich hydrocarbon stream 322 may beseparated into light hydrocarbons stream 326 and bottom hydrocarbonstream 328. In some embodiments, hydrocarbon recovery unit 324 includes30 theoretical distillation stages and is operated at a pressure of 10bar. Light hydrocarbons stream 326 may include hydrocarbons having acarbon number from 2 to 4, a residual amount of hydrogen sulfide,thiols, and/or COS. For example, light hydrocarbons stream 326 may haveabout 30 ppm hydrogen sulfide, 280 ppm thiols and 260 ppm COS. Lighthydrocarbons stream 326 may be treated further (for example, contactedwith molecular sieves) to remove the sulfur compounds. In someembodiments, light hydrocarbons stream 326 requires no furtherpurification and is suitable for transportation and/or use as a fuel.

Hydrocarbon stream 328 may include hydrocarbons having a carbon numberranging from 3 to 7. Some of hydrocarbon stream 328 may be directed toseparation unit 330 and/or separation unit 262 after passing through oneor more heat exchangers 302. Heat exchangers 302 may be integrated withone or more units to maximize energy efficiency. Mixing of hydrocarbonstream 328 with hydrocarbon recovery stream 320 stabilize thecomposition of hydrocarbon recovery stream 320 and avoid build-up ofheavy hydrocarbons and sulfur compounds (for example, organosulfurcompounds). In some embodiments, hydrocarbon stream 328 and hydrocarbonrecovery stream 320 are the same stream. In some embodiments,hydrocarbon stream 328 is treated to remove sulfur compounds (forexample, the hydrocarbon stream is contacted with caustic).

Hydrogen sulfide/hydrocarbon gas stream 318 from cryogenic separationunit 316 may include, but is not limited to, hydrocarbons having acarbon number of at least 3, hydrocarbons that include organosulfurcompounds, hydrogen sulfide, or mixtures thereof. A portion or all ofhydrogen sulfide/hydrocarbon gas stream 318 and hydrocarbon recoverystream 320 enter hydrogen sulfide separation unit 330. Output fromcryogenic separation unit 330 may include hydrogen sulfide stream 260and rich C₃ hydrocarbons stream 332. To facilitate separation of thehydrogen sulfide from rich C₃ hydrocarbon stream 332, a volume ratio of0.73 to 1 of rich C₃ hydrocarbons stream to hydrogen sulfide may beused. In some embodiments, separation unit 330 includes 30 theoreticaldistillation stages. Cryogenic separation unit 330 may be operated at atemperature of about −16° C. and a pressure of about 10 bar. C₃hydrocarbon stream 332 may contain hydrocarbons having a carbon numberof at least 3. At least a portion of C₃ hydrocarbon stream 332 may enterhydrocarbon recovery unit 324.

Hydrogen sulfide stream 260 may include, but is not limited to, hydrogensulfide, C₂ hydrocarbons, C₃ hydrocarbons, carbon dioxide, or mixturesthereof. In some embodiments, hydrogen sulfide stream 260 contains about99 vol % hydrogen sulfide with the balance being C₂ and C₃ hydrocarbons.Hydrogen sulfide stream 260 may be burned to produce SO_(x). In someembodiments, at least a portion of the hydrogen sulfide stream is usedas a fuel in downhole burners. The SO_(x) may be used as a drive fluid,sequestered and/or treated using known techniques in the art.

As shown in FIGS. 7 and 8, in situ heat treatment process liquid stream216 enters liquid separation unit 226. In some embodiments, liquidseparation unit 226 is not necessary. In liquid separation unit 226,separation of in situ heat treatment process liquid stream 216 producesgas hydrocarbon stream 228 and salty process liquid stream 230. Gashydrocarbon stream 228 may include hydrocarbons having a carbon numberof at most 5. A portion of gas hydrocarbon stream 228 may be combinedwith gas hydrocarbon stream 224.

Salty process liquid stream 230 may be processed through desalting unit336 to form liquid stream 338. Desalting unit 336 removes mineral saltsand/or water from salty process liquid stream 230 using known desaltingand water removal methods. In certain embodiments, desalting unit 336 isupstream of liquid separation unit 226.

Liquid stream 338 includes, but is not limited to, hydrocarbons having acarbon number of at least 5 and/or hydrocarbon containing heteroatoms(for example, hydrocarbons containing nitrogen, oxygen, sulfur, andphosphorus). Liquid stream 338 may include at least 0.001 g, at least0.005 g, or at least 0.01 g of hydrocarbons with a boiling rangedistribution between about 95° C. and about 200° C. at 0.101 MPa; atleast 0.01 g, at least 0.005 g, or at least 0.001 g of hydrocarbons witha boiling range distribution between about 200° C. and about 300° C. at0.101 MPa; at least 0.001 g, at least 0.005 g, or at least 0.01 g ofhydrocarbons with a boiling range distribution between about 300° C. andabout 400° C. at 0.101 MPa; and at least 0.001 g, at least 0.005 g, orat least 0.01 g of hydrocarbons with a boiling range distributionbetween 400° C. and 650° C. at 0.101 MPa. In some embodiments, liquidstream 338 contains at most 10% by weight water, at most 5% by weightwater, at most 1% by weight water, or at most 0.1% by weight water.

In some embodiments, the separated liquid stream may have a boilingrange distribution between about 50° C. and about 350° C., between about60° C. and 340° C., between about 70° C. and 330° C. or between about80° C. and 320° C. In some embodiments, the separated liquid stream hasa boiling range distribution between 180° C. and 330° C.

In some embodiments, at least 50%, at least 70%, or at least 90% byweight of the total hydrocarbons in the separated liquid stream have acarbon number from 8 to 13. About 50% to about 100%, about 60% to about95%, about 70% to about 90%, or about 75% to 85% by weight of liquidstream may have a carbon number distribution from 8 to 13. At least 50%by weight of the total hydrocarbons in the separated liquid stream mayhave a carbon number from about 9 to 12 or from 10 to 11.

In some embodiments, the separated liquid stream has at most 15%, atmost 10%, at most 5% by weight of naphthenes; at least 70%, at least80%, or at least 90% by weight total paraffins; at most 5%, at most 3%,or at most 1% by weight olefins; and at most 30%, at most 20%, or atmost 10% by weight aromatics.

In some embodiments, the separated liquid stream has a nitrogen compoundcontent of at least 0.01%, at least 0.1% or at least 0.4% by weightnitrogen compound. The separated liquid stream may have a sulfurcompound content of at least 0.01%, at least 0.5% or at least 1% byweight sulfur compound.

In some embodiments, liquid stream 338 includes organonitrogencompounds. As shown in FIG. 7 liquid stream 338 enters separation unit366. In some embodiments, liquid stream 338 is passed through one ormore filtration units in separation unit 226 to remove solids from theliquid stream. In separation unit 366, liquid stream 338 may be treatedwith an aqueous acid solution 368 to form an aqueous stream 370 andproduct hydrocarbon stream 372. Hydrocarbon stream 372 may include atmost 0.01% by weight nitrogen compounds. Hydrocarbon stream 372 mayenter hydrotreating unit 358.

Aqueous acid solution 368 includes water and acids suitable to complexwith nitrogen compounds (for example, sulfuric acid, phosphoric acid,acetic acid, formic acid and/or other suitable acidic compounds).Aqueous stream 370 includes salts of the organonitrogen compounds andacid and water. At least a portion of aqueous stream 370 is sentseparation unit 374. In separation unit 374, aqueous stream 370 isseparated (for example, distilled) to form aqueous acid stream 368′ andconcentrated organonitrogen stream 375. Concentrated organonitrogenstream 375 includes organonitrogen compounds, water, and/or acid.Separated aqueous stream 368′ may be introduced into separation unit366. In some embodiments, separated aqueous stream 368′ is combined withaqueous acid solution 368 prior to entering the separation unit.

In some embodiments, at least a portion of aqueous stream 370 and/orconcentrated organonitrogen stream 375 are introduced in a hydrocarbonportion or layer of subsurface formation that has been at leastpartially treated by an in situ heat treatment process. Aqueous stream370 and/or concentrated organonitrogen stream 375 may be heated prior toinjection in the formation. In some embodiments, the hydrocarbon portionor layer includes a shale and/or nahcolite (for example, a nahcolitezone in the Piceance Basin). In some embodiments, the aqueous stream 370and/or concentrated organonitrogen stream 375 is used a part of thewater source for solution mining nahcolite from the formation. In someembodiments, the aqueous stream 370 and/or concentrated organonitrogenstream 375 is introduced in a portion of a formation that containsnahcolite after at least a portion of the nahcolite has been removed. Insome embodiments, the aqueous stream 370 and/or concentratedorganonitrogen stream 375 374 is introduced in a portion of a formationthat contains nahcolite after at least a portion of the nahcolite hasbeen removed and/or the portion has been at least partially treatedusing an in situ heat treatment process. The hydrocarbon layer may beheated to temperatures above 200° C. prior to introduction of theaqueous stream. In the heated formation, the organonitrogen compoundsmay form hydrocarbons, amines, and/or ammonia and at least some of suchhydrocarbons, amines and/or ammonia may be produced. In someembodiments, at least some of the acid used in the extraction process isproduced.

In some embodiments, the desalting unit may produce a liquid hydrocarbonstream and a salty process liquid stream, as shown in FIG. 8. In situheat treatment process liquid stream 216 enters liquid separation unit226. Separation unit 226 may include one or more distillation units. Inliquid separation unit 226, separation of in situ heat treatment processliquid stream 216 produces gas hydrocarbon stream 228, salty processliquid stream 230, and liquid hydrocarbon stream 350. Gas hydrocarbonstream 228 may include hydrocarbons having a carbon number of at most 5.A portion of gas hydrocarbon stream 228 may be combined with gashydrocarbon stream 224. Salty process liquid stream 230 may be processedas described in the discussion of FIG. 7. Salty process liquid stream230 may include hydrocarbons having a boiling point above 260° C. Insome embodiments and as depicted in FIG. 8, salty process liquid stream230 enters desalting unit 336. In desalting unit 336, salty processliquid stream 230 may be treated to form liquid stream 338 using knowndesalting and water removal methods. Liquid stream 338 may enterseparation unit 352. In separation unit 352, liquid stream 338 isseparated into bottoms stream 354 and hydrocarbon stream 356. In someembodiments, hydrocarbon stream 356 may have a boiling rangedistribution between about 200° C. and about 350° C., between about 220°C. and 340° C., between about 230° C. and 330° C. or between about 240°C. and 320° C.

In some embodiments, at least 50%, at least 70%, or at least 90% byweight of the total hydrocarbons in hydrocarbon stream 356 have a carbonnumber from 8 to 13. About 50% to about 100%, about 60% to about 95%,about 70% to about 90%, or about 75% to 85% by weight of liquid streammay have a carbon number distribution from 8 to 13. At least 50% byweight of the total hydrocarbons in the separated liquid stream may havea carbon number from about 9 to 12 or from 10 to 11.

In some embodiments, hydrocarbon stream 356 has at most 15%, at most10%, at most 5% by weight of naphthenes; at least 70%, at least 80%, orat least 90% by weight total paraffins; at most 5%, at most 3%, or atmost 1% by weight olefins; and at most 30%, at most 20%, or at most 10%by weight aromatics.

In some embodiments, hydrocarbon stream 356 has a nitrogen compoundcontent of at least 0.01%, at least 0.1% or at least 0.4% by weightnitrogen compound. The separated liquid stream may have a sulfurcompound content of at least 0.01%, at least 0.5% or at least 1% byweight sulfur compound.

Hydrocarbon stream 356 enters hydrotreating unit 358. In hydrotreatingunit 358, liquid stream 338 may be hydrotreated to form compoundssuitable for processing to hydrogen and/or commercial products.

Liquid hydrocarbon stream 350 from liquid separation unit 226 mayinclude hydrocarbons having a boiling point up to 260° C. Liquidhydrocarbon stream 350 may include entrained asphaltenes and/or othercompounds that may contribute to the instability of hydrocarbon streams.For example, liquid hydrocarbon stream 350 is a naphtha/kerosenefraction that includes entrained, partially dissolved, and/or dissolvedasphaltenes and/or high molecular weight compounds that may contributeto phase instability of the liquid hydrocarbon stream. In someembodiments, liquid hydrocarbon stream 350 may include at least 0.5% byweight asphaltenes, 1% by weight asphaltenes or at least 5% by weightasphaltenes.

As properties of the liquid hydrocarbon stream 350 are changed duringprocessing (for example, TAN, asphaltenes, P-value, olefin content,mobilized fluids content, visbroken fluids content, pyrolyzed fluidscontent, or combinations thereof), the asphaltenes and other componentsmay become less soluble in the liquid hydrocarbon stream. In someinstances, components in the produced fluids and/or components in theseparated hydrocarbons may form two phases and/or become insoluble.Formation of two phases, through flocculation of asphaltenes, change inconcentration of components in the produced fluids, change inconcentration of components in separated hydrocarbons, and/orprecipitation of components may cause processing problems (for example,plugging) and/or result in hydrocarbons that do not meet pipeline,transportation, and/or refining specifications. In some embodiments,further treatment of the produced fluids and/or separated hydrocarbonsis necessary to produce products with desired properties.

During processing, the P-value of the separated hydrocarbons may bemonitored and the stability of the produced fluids and/or separatedhydrocarbons may be assessed. Typically, a P-value that is at most 1.0indicates that flocculation of asphaltenes from the separatedhydrocarbons may occur. If the P-value is initially at least 1.0 andsuch P-value increases or is relatively stable during heating, then thisindicates that the separated hydrocarbons are relatively stable.

Liquid hydrocarbon stream 350 may be treated to at least partiallyremove asphaltenes and/or other compounds that may contribute toinstability. Removal of the asphaltenes and/or other compounds that maycontribute to instability may inhibit plugging in downstream processingunits. Removal of the asphaltenes and/or other compounds that maycontribute to instability may enhance processing unit efficienciesand/or prevent plugging of transportation pipelines.

Liquid hydrocarbon stream 350 may enter filtration system 342.Filtration system 342 separates at least a portion of the asphaltenesand/or other compounds that contribute to instability from liquidhydrocarbon stream 350. In some embodiments, filtration system 342 isskid mounted. Skid mounting filtration system 342 may allow thefiltration system to be moved from one processing unit to another. Insome embodiments, filtration system 342 includes one or more membraneseparators, for example, one or more nanofiltration membranes or one ormore reverse osmosis membranes. Use of a filtration system that operatesat below ambient, ambient, or slightly higher than ambient temperaturesmay reduce energy costs as compared to conventional catalytic and/orthermal methods to remove asphaltenes from a hydrocarbon stream.

The membranes may be ceramic membranes and/or polymeric membranes. Theceramic membranes may be ceramic membranes having a molecular weight cutoff of at most 2000 Daltons (Da), at most 1000 Da, or at most 500 Da.Ceramic membranes may not swell during removal of the desired materialsfrom a substrate (for example, asphaltenes from the liquid stream). Inaddition, ceramic membranes may be used at elevated temperatures.Examples of ceramic membranes include, but are not limited to,mesoporous titania, mesoporous gamma-alumina, mesoporous zirconia,mesoporous silica, and combinations thereof.

Polymeric membranes may include top layers made of dense membrane andbase layers (supports) made of porous membranes. The polymeric membranesmay be arranged to allow the liquid stream (permeate) to flow firstthrough the top layers and then through the base layer so that thepressure difference over the membrane pushes the top layer onto the baselayer. The polymeric membranes are organophilic or hydrophobic membranesso that water present in the liquid stream is retained or substantiallyretained in the retentate.

The dense membrane layer of the polymeric membrane may separate at leasta portion or substantially all of the asphaltenes from liquidhydrocarbon stream 350. In some embodiments, the dense polymericmembrane has properties such that liquid hydrocarbon stream 350 passesthrough the membrane by dissolving in and diffusing through thestructure of dense membrane. At least a portion of the asphaltenes maynot dissolve and/or diffuse through the dense membrane, thus they areremoved. The asphaltenes may not dissolve and/or diffuse through thedense membrane because of the complex structure of the asphaltenesand/or their high molecular weight. The dense membrane layer may includecross-linked structure as described in WO 96/27430 to Schmidt et al.,which is incorporated by reference herein. A thickness of the densemembrane layer may range from 1 micrometer to 15 micrometers, from 2micrometers to 10 micrometers, or from 3 micrometers to 5 micrometers.

The dense membrane may be made from polysiloxane, poly-di-methylsiloxane, poly-octyl-methyl siloxane, polyimide, polyaramide,poly-tri-methyl silyl propyne, or mixtures thereof. Porous base layersmay be made of materials that provide mechanical strength to themembrane. The porous base layers may be any porous membranes used forultra filtration, nanofiltration, and/or reverse osmosis. Examples ofsuch materials are polyacrylonitrile, polyamideimide in combination withtitanium oxide, polyetherimide, polyvinylidenedifluoride,polytetrafluoroethylene, or combinations thereof.

During separation of asphaltenes from liquid stream 350, the pressuredifference across the membrane may range from about 0.5 MPa to about 6MPa, from about 1 MPa to about 5 MPa, or from about 2 MPa to about 4MPa. A temperature of the unit during separation may range from the pourpoint of liquid hydrocarbon stream 350 up to 100° C., from about −20° C.to about 100° C., from about 10° C. to about 90° C., or from about 20°C. to about 85° C. During continuous operation, the permeate flux ratemay be at most 50% of the initial flux, at most 70% of the initial flux,or at most 90% of the initial flux. A weight recovery of the permeate onfeed may range from about 50% by weight to 97% by weight, from about 60%by weight to 90% by weight, or from about 70% by weight to 80% byweight.

Filtration system 342 may include one or more membrane separators. Themembrane separators may include one or more membrane modules. When twoor more membrane separators are used, the separators may be arranged ina parallel configuration to allow feed (retentate) from a first membraneseparator to flow into a second membrane separator. Examples of membranemodules include, but are not limited to, spirally wound modules, plateand frame modules, hollow fibers, and tubular modules. Membrane modulesare described in Encyclopedia of Chemical Engineering, 4b Ed., 1995,John Wiley & Sons Inc., Vol. 16, pages 158-164. Examples of spirallywound modules are described in, for example, WO/2006/040307 to Boestertet al., U.S. Pat. Nos. 5,102,551 to Pasternak; 5,093,002 to Pasternak;5,275,726 to Feimer et al.; 5,458,774 to Mannapperuma; and 5,150,118 toFinkle et al, all of which are incorporated by reference herein.

In some embodiments, a spirally wound module is used when a densemembrane is used in filtration system 342. A spirally wound module mayinclude a membrane assembly of two membrane sheets between which apermeate spacer sheet is sandwiched. The membrane assembly may be sealedat three sides. The fourth side is connected to a permeate outletconduit such that the area between the membranes is in fluidcommunication with the interior of the conduit. A feed spacer sheet maybe arranged on top of one of the membranes. The assembly with feedspacer sheet is rolled up around the permeate outlet conduit to form asubstantially cylindrical spirally wound membrane module. The feedspacer may have a thickness of at least 0.6 mm, at least 1 mm, or atleast 3 mm to allow sufficient membrane surface to be packed into thespirally wound module. In some embodiments, the feed spacer is a wovenfeed spacer. During operation, the feed mixture may be passed from oneend of the cylindrical module between the membrane assemblies along thefeed spacer sheet sandwiched between feed sides of the membranes. Partof the feed mixture passes through either one of the membrane sheets tothe permeate side. The resulting permeate flows along the permeatespacer sheet into the permeate outlet conduit.

In some embodiments, the membrane separation is a continuous process.Liquid stream 350 passes over the membrane due to the pressuredifference to obtain filtered liquid stream 360 (permeate) and/orrecycle liquid stream 362 (retentate). In some embodiments, filteredliquid stream 360 may have reduced concentrations of asphaltenes and/orhigh molecular weight compounds that may contribute to phaseinstability. Continuous recycling of recycle liquid stream 362 throughthe filter system can increase the production of filtered liquid stream360 to as much as 95% of the original volume of filtered liquid stream360. Recycle liquid stream 362 may be continuously recycled through aspirally wound membrane module for at least 10 hours, for at least oneday, or for at least one week without cleaning the feed side of themembrane. Upon completion of the filtration, asphaltene enriched stream364 (retentate) may include a high concentration of asphaltenes and/orhigh molecular weight compounds.

In some embodiments, liquid stream 338 is contacted with hydrogen in thepresence of one or more catalysts to change one or more desiredproperties of the crude feed to meet transportation and/or refineryspecifications using known hydrodemetallation, hydrodesulfurization,hydrodenitrofication techniques. Other methods to change one or moredesired properties of the crude feed are described in U.S. PublishedPatent Applications Nos. 2005-0133414; 2006-0231465; and 2007-0000810 toBhan et al.; 2005-0133405 to Wellington et al.; and 2006-0289340 toBrownscombe et al., all of which are incorporated by reference herein.

In some embodiments, the hydrotreated liquid stream has a nitrogencompound content of at most 200 ppm by weight, at most 150 ppm, at most110 ppm, at most 50 ppm, or at most 10 ppm of nitrogen compounds. Theseparated liquid stream may have a sulfur compound content of at most1000 ppm, at most 500 ppm, at most 300 ppm, at most 100 ppm, or at most10 ppm by weight of sulfur compounds.

As shown in FIG. 7 and FIG. 8, liquid stream 338 and/or filtered liquidstream 344 may enter hydrotreating unit 358. In some embodiments,hydrogen source 376 enters hydrotreating unit 358 in addition to liquidstream 338 and/or filtered liquid stream 344. In some embodiments, thehydrogen source is not needed. Liquid stream 338 and/or filtered liquidstream 344 may be selectively hydrogenated in hydrotreating unit 358such that di-olefins are reduced to mono-olefins. For example, liquidstream 338 and/or filtered liquid stream 344 is contacted with hydrogenin the presence of DN-200 (Criterion Catalysts & Technologies, HoustonTex., U.S.A.) at temperatures ranging from 100° C. to 200° C. and totalpressures of 0.1 MPa to 40 MPa to produce liquid stream 378. In someembodiments, filtered liquid stream 344 is hydrotreated at a temperatureranging from about 190° C. to about 200° C. at a pressure of at least 6MPa. Liquid stream 378 includes a reduced content of di-olefins and anincreased content of mono-olefins relative to the di-olefin andmono-olefin content of liquid stream 338. In some embodiments, theconversion of di-olefins to mono-olefins under these conditions is atleast 50%, at least 60%, at least 80% or at least 90%. Liquid stream 378exits hydrotreating unit 358 and enters one or more processing unitspositioned downstream of hydrotreating unit 358. The units positioneddownstream of hydrotreating unit 358 may include distillation units,catalytic reforming units, hydrocracking units, hydrotreating units,hydrogenation units, hydrodesulfurization units, catalytic crackingunits, delayed coking units, gasification units, or combinationsthereof. In some embodiments, hydrotreating prior to fractionation isnot necessary. In some embodiments, liquid stream 378 may be severelyhydrotreated to remove undesired compounds from the liquid stream priorto fractionation. In certain embodiments, liquid stream 378 may befractionated and the produced streams may each be hydrotreated to meetindustry standards and/or transportation standards.

Liquid stream 378 may exit hydrotreating unit 358 and enterfractionation unit 380. In fractionation unit 380, liquid stream 378 maybe distilled to form one or more crude products. Crude products include,but are not limited to, C₃-C₅ hydrocarbon stream 382, naphtha stream384, kerosene stream 386, diesel stream 388, and bottoms stream 354.Fractionation unit 380 may be operated at atmospheric and/or undervacuum conditions.

In some embodiments, hydrotreated liquid streams and/or streams producedfrom fractions (for example, aromatic rich streams, distillates and/ornaphtha) are blended with the in situ heat treatment process liquidand/or formation fluid to produce a blended fluid. The blended fluid mayhave enhanced physical stability and chemical stability as compared tothe formation fluid. The blended fluid may have a reduced amount ofreactive species (for example, di-olefins, other olefins and/orcompounds containing oxygen, sulfur and/or nitrogen) relative to theformation fluid. Thus, chemical stability of the blended fluid isenhanced. The blended fluid may decrease an amount of asphaltenesrelative to the formation fluid. Thus, physical stability of the blendedfluid is enhanced. The blended fluid may be a more a fungible feed thanthe formation fluid and/or the liquid stream produced from the in situheat treatment process. The blended feed may be more suitable fortransportation, for use in chemical processing units and/or for use inrefining units than formation fluid.

In some embodiments, a fluid produced by methods described herein froman oil shale formation may be blended with heavy oil/tar sands in situheat treatment process (IHTP) fluid. Blended fluids may have properties(for example, viscosity and/or P-value) that make the blended fluid moreacceptable for transportation and/or distribution to processing units.In some embodiments, produced oil shale fluid may be blended withbitumen to produce a blended bitumen having acceptable viscosity and/orstability properties. Thus, the blended bitumen may be transportedand/or distributed to processing units.

As shown in FIG. 7 and FIG. 8, C₃-C₅ hydrocarbon stream 382 producedfrom fractionation unit 380 and/or hydrocarbon gas stream 224 enteralkylation unit 396. In alkylation unit 396, reaction of the olefins inhydrocarbon gas stream 224 (for example, propylene, butylenes, amylenes,or combinations thereof) with the iso-paraffins in C₃-C₅ hydrocarbonstream 382 produces hydrocarbon stream 398. In some embodiments, theolefin content in hydrocarbon gas stream 224 is acceptable and anadditional source of olefins is not needed. Hydrocarbon stream 398includes hydrocarbons having a carbon number of at least 4. Hydrocarbonshaving a carbon number of at least 4 include, but are not limited to,butanes, pentanes, hexanes, heptanes, and octanes. In certainembodiments, hydrocarbons produced from alkylation unit 396 have anoctane number greater than 70, greater than 80, or greater than 90. Insome embodiments, hydrocarbon stream 398 is suitable for use as gasolinewithout further processing.

In some embodiments, and as depicted in FIG. 7 and FIG. 8, bottomsstream 354 may be hydrocracked to produce naphtha and/or other products.The resulting naphtha may, however, need reformation to alter the octanelevel so that the product may be sold commercially as gasoline.Alternatively, bottoms stream 354 may be treated in a catalytic crackerto produce naphtha and/or feed for an alkylation unit. In someembodiments, naphtha stream 384, kerosene stream 386, and diesel stream388 have an imbalance of paraffinic hydrocarbons, olefinic hydrocarbons,and/or aromatic hydrocarbons. The streams may not have a suitablequantity of olefins and/or aromatics for use in commercial products.This imbalance may be changed by combining at least a portion of thestreams to form combined stream 400 which has a boiling rangedistribution from about 38° C. to about 343° C. Catalytically crackingcombined stream 400 may produce olefins and/or other streams suitablefor use in an alkylation unit and/or other processing units. In someembodiments, naphtha stream 384 is hydrocracked to produce olefins.

Combined stream 400 and bottoms stream 354 from fractionation unit 380enter catalytic cracking unit 402. Under controlled cracking conditions(for example, controlled temperatures and pressures), catalytic crackingunit 402 produces additional C₃-C₅ hydrocarbon stream 382′, gasolinehydrocarbons stream 404, and additional kerosene stream 386′.

Additional C₃-C₅ hydrocarbon stream 382′ may be sent to alkylation unit396, combined with C₃-C₅ hydrocarbon stream 382, and/or combined withhydrocarbon gas stream 224 to produce gasoline suitable for commercialsale. In some embodiments, the olefin content in hydrocarbon gas stream224 is acceptable and an additional source of olefins is not needed.

Many wells are needed for treating the hydrocarbon formation using thein situ heat treatment process. In some embodiments, vertical orsubstantially vertical wells are formed in the formation. In someembodiments, horizontal or U-shaped wells are formed in the formation.In some embodiments, combinations of horizontal and vertical wells areformed in the formation.

A manufacturing approach for forming wellbores in the formation may beused due to the large number of wells that need to be formed for the insitu heat treatment process. The manufacturing approach may beparticularly applicable for forming wells for in situ heat treatmentprocesses that utilize u-shaped wells or other types of wells that havelong non-vertically oriented sections. Surface openings for the wellsmay be positioned in lines running along one or two sides of thetreatment area. FIG. 9 depicts a schematic representation of anembodiment of a system for forming wellbores of the in situ heattreatment process.

The manufacturing approach for forming wellbores may include: 1)delivering flat rolled steel to near site tube manufacturing plant thatforms coiled tubulars and/or pipe for surface pipelines; 2)manufacturing large diameter coiled tubing that is tailored to therequired well length using electrical resistance welding (ERW), whereinthe coiled tubing has customized ends for the bottom hole assembly (BHA)and hang off at the wellhead; 3) deliver the coiled tubing to a drillingrig on a large diameter reel; 4) drill to total depth with coil and aretrievable bottom hole assembly; 5) at total depth, disengage the coiland hang the coil on the wellhead; 6) retrieve the BHA; 7) launch anexpansion cone to expand the coil against the formation; 8) return emptyspool to the tube manufacturing plant to accept a new length of coiledtubing; 9) move the gantry type drilling platform to the next welllocation; and 10) repeat.

In situ heat treatment process locations may be distant from establishedcities and transportation networks. Transporting formed pipe or coiledtubing for wellbores to the in situ process location may be untenabledue to the lengths and quantity of tubulars needed for the in situ heattreatment process. One or more tube manufacturing facilities 406 may beformed at or near to the in situ heat treatment process location. Thetubular manufacturing facility may form plate steel into coiled tubing.The plate steel may be delivered to tube manufacturing facilities 406 bytruck, train, ship or other transportation system. In some embodiments,different sections of the coiled tubing may be formed of differentalloys. The tubular manufacturing facility may use ERW to longitudinallyweld the coiled tubing.

Tube manufacturing facilities 406 may be able to produce tubing havingvarious diameters. Tube manufacturing facilities may initially be usedto produce coiled tubing for forming wellbores. The tube manufacturingfacilities may also be used to produce heater components, piping fortransporting formation fluid to surface facilities, and other piping andtubing needs for the in situ heat treatment process.

Tube manufacturing facilities 406 may produce coiled tubing used to formwellbores in the formation. The coiled tubing may have a large diameter.The diameter of the coiled tubing may be from about 4 inches to about 8inches in diameter. In some embodiments, the diameter of the coiledtubing is about 6 inches in diameter. The coiled tubing may be placed onlarge diameter reels. Large diameter reels may be needed due to thelarge diameter of the tubing. The diameter of the reel may be from about10 m to about 50 m. One reel may hold all of the tubing needed forcompleting a single well to total depth.

In some embodiments, tube manufacturing facilities 406 has the abilityto apply expandable zonal inflow profiler (EZIP) material to one or moresections of the tubing that the facility produces. The EZIP material maybe placed on portions of the tubing that are to be positioned near andnext to aquifers or high permeability layers in the formation. Whenactivated, the EZIP material forms a seal against the formation that mayserve to inhibit migration of formation fluid between different layers.The use of EZIP layers may inhibit saline formation fluid from mixingwith non-saline formation fluid.

The size of the reels used to hold the coiled tubing may prohibittransport of the reel using standard moving equipment and roads. Becausetube manufacturing facility 406 is at or near the in situ heat treatmentlocation, the equipment used to move the coiled tubing to the well sitesdoes not have to meet existing road transportation regulations and canbe designed to move large reels of tubing. In some embodiments theequipment used to move the reels of tubing is similar to cargo gantriesused to move shipping containers at ports and other facilities. In someembodiments, the gantries are wheeled units. In some embodiments, thecoiled tubing may be moved using a rail system or other transportationsystem.

The coiled tubing may be moved from the tubing manufacturing facility tothe well site using gantries 408. Drilling gantry 410 may be used at thewell site. Several drilling gantries 410 may be used to form wellboresat different locations. Supply systems for drilling fluid or other needsmay be coupled to drilling gantries 410 from central facilities 412.

Drilling gantry 410 or other equipment may be used to set the conductorfor the well. Drilling gantry 410 takes coiled tubing, passes the coiledtubing through a straightener, and a BHA attached to the tubing is usedto drill the wellbore to depth. In some embodiments, a composite coil ispositioned in the coiled tubing at tube manufacturing facility 406. Thecomposite coil allows the wellbore to be formed without having drillingfluid flowing between the formation and the tubing. The composite coilalso allows the BHA to be retrieved from the wellbore. The compositecoil may be pulled from the tubing after wellbore formation. Thecomposite coil may be returned to the tubing manufacturing facility tobe placed in another length of coiled tubing. In some embodiments, theBHAs are not retrieved from the wellbores.

In some embodiments, drilling gantry 410 takes the reel of coiled tubingfrom gantry 408. In some embodiments, gantry 408 is coupled to drillinggantry 410 during the formation of the wellbore. For example, the coiledtubing may be fed from gantry 408 to drilling gantry 410, or thedrilling gantry lifts the gantry to a feed position and the tubing isfed from the gantry to the drilling gantry.

The wellbore may be formed using the bottom hole assembly, coiled tubingand the drilling gantry. The BHA may be self-seeking to the destination.The BHA may form the opening at a fast rate. In some embodiments, theBHA forms the opening at a rate of about 100 meters per hour.

After the wellbore is drilled to total depth, the tubing may besuspended from the wellhead. An expansion cone may be used to expand thetubular against the formation. In some embodiments, the drilling gantryis used to install a heater and/or other equipment in the wellbore.

When drilling gantry 410 is finished at well site 414, the drillinggantry may release gantry 408 with the empty reel or return the emptyreel to the gantry. Gantry 408 may take the empty reel back to tubemanufacturing facility 406 to be loaded with another coiled tube.Gantries 408 may move on looped path 416 from tube manufacturingfacility 406 to well sites 414 and back to the tube manufacturingfacility.

Drilling gantry 410 may be moved to the next well site. Globalpositioning satellite information, lasers and/or other information maybe used to position the drilling gantry at desired locations. Additionalwellbores may be formed until all of the wellbores for the in situ heattreatment process are formed.

In some embodiments, positioning and/or tracking system may be utilizedto track gantries 408, drilling gantries 410, coiled tubing reels andother equipment and materials used to develop the in situ heat treatmentlocation. Tracking systems may include bar code tracking systems toensure equipment and materials arrive where and when needed.

Directionally drilled wellbores may be formed using steerable motors.Deviations in wellbore trajectory may be made using slide drillingsystems or using rotary steerable systems. During use of slide drillingsystems, the mud motor rotates the bit downhole with little or norotation of the drilling string from the surface during trajectorychanges. The bottom hole assembly is fitted with a bent sub and/or abent housing mud motor for directional drilling. The bent sub and thedrill bit are oriented in the desired direction. With little or norotation of the drilling string, the drill bit is rotated with the mudmotor to set the trajectory. When the desired trajectory is obtained,the entire drilling string is rotated and drills straight rather than atan angle. Drill bit direction changes may be made by utilizingtorque/rotary adjusting to control the drill bit in the desireddirection.

By controlling the amount of wellbore drilled in the sliding androtating modes, the wellbore trajectory may be controlled. Torque anddrag during sliding and rotating modes may limit the capabilities ofslide mode drilling. Steerable motors may produce tortuosity in theslide mode. Tortuosity may make further sliding more difficult. Manymethods have been developed, or are being developed, to improve slidedrilling systems. Examples of improvements to slide drilling systemsinclude agitators, low weight bits, slippery muds, and torque/toolfacecontrol systems.

Limitations in slide drilling led to the development of rotary steerablesystems. Rotary steerable systems allow directional drilling withcontinuous rotation from the surface, thus making the need to slide thedrill string unnecessary. Continuous rotation transfers weight to thedrill bit more efficiently, thus increasing the rate of penetration.Current rotary steerable systems may be mechanically and/or electricallycomplicated with a high cost of delivery due to service companiesrequiring a high rate of return and due to relatively high failure ratesfor the systems.

In some embodiments, a dual motor rotary steerable system is used. Thedual motor rotary steerable system allows a bent sub and/or bent housingmud motor to change the trajectory of the drilling while the drillingstring remains in rotary mode. The dual motor rotary steerable systemuses a second motor in the bottom hole assembly to rotate a portion ofthe bottom hole assembly in a direction opposite to the direction ofrotation of the drilling string. The addition of the second motor mayallow continuous forward rotation of a drilling string whilesimultaneously controlling the drill bit and, thus, the directionalresponse of the bottom hole assembly. In some embodiments, the rotationspeed of the drilling string is used in achieving drill bit control.

FIG. 10 depicts a schematic representation of an embodiment of drillingstring 418 with dual motors in bottom hole assembly 420. Drilling string418 is coupled to bottom hole assembly 420. Bottom hole assembly 420includes motor 422A and motor 422B. Motor 422A may be a bent sub and/orbent housing steerable mud motor. Motor 422A may drive drill bit 424.Motor 422B may operate in a rotation direction that is opposite to therotation of drilling string 418 and/or motor 422A. Motor 422B mayoperate at a relatively low rotary speed and have high torque capacityas compared to motor 422A. Bottom hole assembly 420 may include sensingarray 426 between motors 422A, motor 422B.

As noted above, motor 422B may rotate in a direction opposite to therotation of drilling string 418. In this manner, portions of bottom holeassembly 420 beyond motor 422B may have less rotation in the directionof rotation of drilling string 418. The revolutions per minute (rpm)versus differential pressure relationship for bottom hole assembly 420may be assessed prior to running drilling string 418 and the bottom holeassembly 420 in the formation to determine the differential pressure atneutral drilling speed (when the drilling string speed is equal andopposite to the speed of motor 422B). Measured differential pressure maybe used by a control system during drilling to control the speed of thedrilling string relative to the neutral drilling speed.

In some embodiments, motor 422B is operated at a substantially fixedspeed. For example, motor 422B may be operated at a speed of 30 rpm.Other speeds may be used as desired.

In some embodiments, a mud motor is installed in a bottom hole assemblyin an inverted orientation (for example, upside-down from the normalorientation). The inverted mud motor may be operated in a reversedirection of rotation relative to other mud motors, a drill bit, and/ora drilling string. For example, motor 422B, shown in FIG. 10, may beinstalled in an inverted orientation to produce a relativecounter-clockwise rotation in portions of bottom hole assembly 420distal to motor 422B (see counterclockwise arrow). Installing a mudmotor in an inverted orientation may allow for the use of off-the-shelfmotors to produce counter-rotation and/or non-rotation of selectedelements of the bottom hole assembly. In one embodiment, a threading kitis used to adapt a threaded mounting for mud motor to ensure that asecure connection between an inverted mud motor and its mounting ismaintained during drilling (e.g., by reversing the threads).

In some embodiments, the rotation speed of drilling string 418 is usedto control the trajectory of the wellbore being formed. For example,drilling string 418 may initially be rotating at 40 rpm, and motor 422Brotates at 30 rpm. The counter-rotation of motor 422B and drillingstring 418 results in a forward rotation speed (for example, an absoluteforward rotation speed) of 10 rpm in the lower portion of bottom holeassembly 420 (the portion of the bottom hole assembly below motor 422B).When a directional course correction is to be made, the speed ofdrilling string 418 is changed to the neutral drilling speed. Becausedrilling string 418 is rotating, there is no need to lift drill bit 424off the bottom of the borehole. Operating at neutral drilling speed mayeffectively cancel the torque of the drilling string so that drill bit424 is subjected to torque induced by motor 422A and the formation.

The continuous rotation of drilling string 418 keeps windup of thedrilling string consistent and stabilizes drill bit 424. Directionalchanges of drill bit 424 may be made by changing the speed of drillingstring 418. Using a dual motor rotary steerable system allows thechanging of the direction of the drilling string to occur while thedrilling string rotates at or near the normal operating rotation speedof drilling string 418. FIG. 11 depicts time at drilling string rotationduring direction change versus rotation speed (rpm) of the drillingstring for a conventional steerable motor bottom hole assembly during adrill bit direction change. FIG. 12 depicts time at rotation speedduring directional change versus change in drilling string rotatingspeed for the dual motor drilling string during the drill bit directionchange. Drill bit control may be substantially the same as forconventional slide mode drilling where torque/rotary adjustment is usedto control the drill bit in the desired direction, but to the effectthat 0 rpm on the x-axis of FIG. 11 becomes N (the neutral drillingstring speed) in FIG. 12.

The connection of bottom hole assembly 420 to drilling string 418 of thedual motor rotary steerable system depicted in FIG. 10 may be subjectedto the net effect of all the torque components required to rotate theentire bottom hole assembly (including torque generated at drill bit 424during wellbore formation). Threaded connections along drilling string418 may include profile-matched sleeves such as those known in the artfor utilities drilling systems.

In some embodiments, a control system used to control wellbore formationincludes a system that sets a desired rotation speed of drilling string418 when direction changes in trajectory of the wellbore are to beimplemented. The system may include fine tuning of the desired drillingstring rotation speed.

In certain embodiments, drilling string 418 is integrated with positionmeasurement and down hole tools (for example, sensing array 426) toautonomously control the hole path along a designed geometry. Anautonomous control system for controlling the path of drilling string418 may utilize two or more domains of functionality. In one embodiment,a control system utilizes at least three domains of functionalityincluding, but not limited to, measurement, trajectory, and control.Measurement may be made using sensor systems and/or other equipmenthardware that assess angles, distances, magnetic fields, and/or otherdata. Trajectory may include flight path calculation and algorithms thatutilize physical measurements to calculate angular and spatial offsetsof the drilling string. The control system may implement actions to keepthe drilling string in the proper path. The control system may includetools that utilize software/control interfaces built into an operatingsystem of the drilling equipment, drilling string and/or bottom holeassembly.

In certain embodiments, the control system utilizes position and anglemeasurements to define spatial and angular offsets from the desireddrilling geometry. The defined offsets may be used to determine asteering solution to move the trajectory of the drilling string (thus,the trajectory of the borehole) back into convergence with the desireddrilling geometry. The steering solution may be based on an optimumalignment solution in which a desired rate of curvature of the boreholepath is set, and required angle change segments and angle changedirections for the path are assessed (for example, by computation).

In some embodiments, the control system uses a fixed angle change rateassociated with the drilling string, assesses the lengths of thesections of the drilling string, and assesses the desired directions ofthe drilling to autonomously execute and control movement of thedrilling string. Thus, the control system assesses position measurementsand controls of the drilling string to control the direction of thedrilling string.

In some embodiments, differential pressure or torque across motor 422Aand/or motor 422B is used to control the rate of penetration. Arelationship between rate of penetration, weight-on-bit, and torque maybe assessed for drilling string 418. Measurements of torque and the rateof penetration/weight-on-bit/torque relationship may be used to controlthe feed rate of drilling string 418 into the formation.

Accuracy and efficiency in forming wellbores in subsurface formationsmay be affected by the density and quality of directional data duringdrilling. The quality of directional data may be diminished byvibrations and angular accelerations during rotary drilling, especiallyduring rotary drilling segments of wellbore formation using slide modedrilling.

In certain embodiments, the quality of the data assessed during rotarydrilling is increased by installing directional sensors in anon-rotating housing. FIG. 13 depicts an embodiment of drilling string418 with non-rotating sensor 432. Non-rotating sensor 432 is locatedbehind motor 422. Motor 422 may be a steerable motor. Motor 422 islocated behind drill bit 424. In certain embodiments, sensor 432 islocated between non-magnetic components in drilling string 418.

In some embodiments, non-rotating sensor 432 is located in a sleeve overmotor 422. In some embodiments, non-rotating sensor 432 is run on abottom hole assembly for improved data assessment. In an embodiment, anon-rotating sensor is coupled to and/or driven by a motor that producesrelative counter-rotation of the sensor relative to other components ofthe bottom hole assembly. For example, a sensor may be coupled to motorhaving a rotation speed equal and opposite to that of bottom holeassembly housing to which it is attached so that the absolute rotationspeed of the sensor is or is substantially zero. In certain embodiments,the motor for a sensor is a mud motor installed in an invertedorientation such as described above relative to FIG. 10.

In certain embodiments, non-rotating sensor 432 includes one or moretransceivers for communicating data either into drilling string 418within the bottom hole assembly or to similar transceivers in nearbyboreholes. The transceivers may be used for telemetry of data and/or asa means of position assessment or verification. In certain embodiments,use of non-rotating sensor 432 is used for continuous positionmeasurement. Continuous position measurement may be useful in controlsystems used for drilling position systems and/or umbilical positioncontrol.

FIG. 14 depicts an embodiment for assessing a position of a firstwellbore relative to a second wellbore using multiple magnets. Firstwellbore 428A is formed in a subsurface formation. Wellbore 428A may beformed by directionally drilling in the formation along a desired path.For example, wellbore 428A may be horizontally or vertically drilled, ordrilled at an inclined angle, in the subsurface formation.

Second wellbore 428B may be formed in the subsurface formation withdrill bit 424 on drilling string 418. In certain embodiments, drillingstring 418 includes one or more magnets 430. Wellbore 428B may be formedin a selected relationship to wellbore 428A. In certain embodiments,wellbore 428B is formed substantially parallel to wellbore 428A. Inother embodiments, wellbore 428B is formed at other angles relative towellbore 428A. In some embodiments, wellbore 428B is formedperpendicular to wellbore 428A.

In certain embodiments, wellbore 428A includes sensing array 426.Sensing array 426 may include two or more sensors 432. Sensors 432 maysense magnetic fields produced by magnets 430 in wellbore 428B. Thesensed magnetic fields may be used to assess a position of wellbore 428Arelative to wellbore 428B. In some embodiments, sensors 432 measure twoor more magnetic fields provided by magnets 430.

Two or more sensors 432 in wellbore 428A may allow for continuousassessment of the relative position of wellbore 428A versus wellbore428B. Using two or more sensors 432 in wellbore 428A may also allow thesensors to be used as gradiometers. In some embodiments, sensors 432 arepositioned in advance (ahead of) magnets 430. Positioning sensors 432 inadvance of magnets 430 allows the magnets to traverse past the sensorsso that the magnet's position (the position of wellbore 428B) ismeasurable continuously or “live” during drilling of wellbore 428B.Sensing array 426 may be moved intermittently (at selected intervals) tomove sensors 432 ahead of magnets 430. Positioning sensors 432 inadvance of magnets 430 also allows the sensors to measure, store, andzero the Earth's field before sensing the magnetic fields of themagnets. The Earth's field may be zeroed by, for example, using a nullfunction before arrival of the magnets, calculating backgroundcomponents from a known sensor attitude, or using paired sensors thatfunction as gradiometers.

The relative position of wellbore 428B versus wellbore 428A may be usedto adjust the drilling of wellbore 428B using drilling string 418. Forexample, the direction of drilling for wellbore 428B may be adjusted sothat wellbore 428B remains a set distance away from wellbore 428A andthe wellbores remain substantially parallel. In certain embodiments, thedrilling of wellbore 428B is continuously adjusted based on continuousposition assessments made by sensors 432. Data from drilling string 418(for example, orientation, attitude, and/or gravitational data) may becombined or synchronized with data from sensors 432 to continuouslyassess the relative positions of the wellbores and adjust the drillingof wellbore 428B accordingly. Continuously assessing the relativepositions of the wellbores may allow for coiled tubing drilling ofwellbore 428B.

In some embodiments, drilling string 418 may include two or more sensingarrays. The sensing arrays may include two or more sensors. Using two ormore sensing arrays in drilling string 418 may allow for directmeasurement of magnetic interference of magnets 430 on the measurementof the Earth's magnetic field. Directly measuring any magneticinterference of magnets 430 on the measurement of the Earth's magneticfield may reduce errors in readings (for example, error to pointingazimuth). The direct measurement of the field gradient from the magnetsfrom within drill string 418 also provides confirmation of referencefield strength of the field to be measured from within wellbore 428A.

FIG. 15 depicts an embodiment for assessing a position of a firstwellbore relative to a second wellbore using a continuous pulsed signal.Signal wire 434 may be placed in wellbore 428A. Sensor 432 may belocated in drilling string 418 in wellbore 428B. In certain embodiments,wire 434 provides a current path and/or reference voltage signal (forexample, a pulsed DC reference signal) into wellbore 428A. In oneembodiment, the reference voltage signal is a 10 Hz pulsed DC signal. Inone embodiment, the reference voltage signal is a 5 Hz pulsed DC signal.In some embodiments, the reference voltage signal is between 0.5 Hzpulsed DC signal and 0.75 Hz pulsed DC signal. Providing the currentpath and reference voltage signal may generate a known and, in someembodiments, fixed current in wellbore 428A. In some embodiments, thevoltage signal is automatically varied on the surface to generate auniform fixed current in the wellbore. Automatically varying the voltagesignal on the surface may minimize bandwidth needs by reducing oreliminating the need to send current downhole and/or sensor raw datauphole.

In some embodiments, wire 434 carries current into and out of wellbore428A (the forward and return conductors are both on the wire). In someembodiments, wire 434 carries current into wellbore 428A and the currentis returned on a casing in the wellbore (for example, the casing of aheater or production conduit in the wellbore). In some embodiments, wire434 carries current into wellbore 428A and the current is returned onanother conductor located in the formation. For example, current flowsfrom wire 434 in wellbore 428A through the formation to an electrode(current return) in the formation. In certain embodiments, current flowsout an end of wellbore 428A. The electrode may be, for example, anelectrode in another wellbore in the formation or a bare electrodeextending from another wellbore in the formation. The electrode may bethe casing in another wellbore in the formation. In some embodiments,wellbore 428A is substantially horizontal in the formation and currentflows from wire 434 in the wellbore to a bare electrode extending from asubstantially vertical wellbore in the formation.

The electromagnetic field provided by the voltage signal may be sensedby sensor 432. The sensed signal may be used to assess a position ofwellbore 428B relative to wellbore 428A.

In some embodiments, wire 434 is a ranging wire located in wellbore428A. In some embodiments, the voltage signal is provided by anelectrical conductor that will be used as part of a heater in wellbore428A. In some embodiments, the voltage signal is provided by anelectrical conductor that is part of a heater or production equipmentlocated in wellbore 428A. Wire 434, or other electrical conductors usedto provide the voltage signal, may be grounded so that there is nocurrent return along the wire or in the wellbore. Return current maycancel the electromagnetic field produced by the wire.

Where return current exists, the current may be measured and modeled togenerate a “net current” from which a resultant electromagnetic fieldmay be resolved. For example, in some areas, a 600 A signal current mayonly yield a 3-6 A net current. In some embodiments where it is notfeasible to eliminate sufficient return current along the wellborecontaining the conductor, two conductors may be installed in separatewellbores. In this method, signal wires from each of the existingwellbores are connected to opposite voltage terminals of the signalgenerator. The return current path is in this way guided through theearth from the contactor region of one conductor to the other. Incertain embodiments, calculations are used to assess (determine) theamount of voltage needed to conduct current through the formation.

In certain embodiments, the reference voltage signal is turned on andoff (pulsed) so that multiple measurements are taken by sensor 432 overa selected time period. The multiple measurements may be averaged toreduce or eliminate resolution error in sensing the reference voltagesignal. In some embodiments, providing the reference voltage signal,sensing the signal, and adjusting the drilling based on the sensedsignals are performed continuously without providing any data to thesurface or any surface operator input to the downhole equipment. Forexample, an automated system located downhole may be used to perform allthe downhole sensing and adjustment operations. In some embodiments, aniterative process is used to perform calculations used in the automateddownhole sensing and adjustment operations. In certain embodiments,distance and direction are calculated continuously downhole, filteredand averaged. A best estimate final distance and direction may be outputto the surface and combined with known along hole depth and sourcelocation to determine three-axis position data.

The signal field generated by the net current passing through theconductors may be resolved from the general background field existingwhen the signal field is “off”. A method for resolving the signal fieldfrom the general background field on a continuous basis may include: 1.)calculating background components based on the known attitude of thesensors and the known value background field strength and dip; 2.) asynchronized “null” function to be applied immediately before thereference field is switched “on”; 3.) Synchronized sampling of forwardand reversed DC polarities (the subtraction of these sampled values mayeffectively remove the background field yielding the reference totalcurrent field); and/or 4.) Sampling values of background magnetic fieldat one or more fixed sampling frequencies and storing them forsubtraction from the reference signal “on” data.

In some embodiments, slight changes in the sensor roll position and/ormovement of the sensor between sampling steps (for example, betweensamples of signal off and signal on data) is compensated or counteractedby rotating the sensor data coordinate system to a reference attitude(for example, a “zero”) after each sample is taken or after a set ofdata is taken. For example, the sensor data coordinate system may berotated to a tensor coordinate system. Parameters such as position,inclination, roll, and/or azimuth of the sensor may be calculated usingsensor data rotated to the tensor coordinate system. In someembodiments, adjustments in calculations and/or data gathering are madeto adjust for sensing and ranging at low wellbore inclination angles(for example, angles near vertical).

FIG. 16 depicts an embodiment for assessing a position of a firstwellbore relative to a second wellbore using a radio ranging signal.Sensor 432 may be placed in wellbore 428A. Source 436 may be located indrilling string 418 in wellbore 428B. In some embodiments, source 436 islocated in wellbore 428A and sensor 432 is located in wellbore 428B. Incertain embodiments, source 436 is an electromagnetic wave producingsource. For example, source 436 may be an electromagnetic sonde. Sensor432 may be an antenna (for example, an electromagnetic or radioantenna). In some embodiments sensor 432 is located in part of a heaterin wellbore 428A.

The signal provided by source 436 may be sensed by sensor 432. Thesensed signal may be used to assess a position of wellbore 428B relativeto wellbore 428A. In certain embodiments, the signal is continuouslysensed using sensor 432. “Continuous” or “continuously” in the contextof sensing signals (such as magnetic, electromagnetic, voltage, or otherelectrical or magnetic signals) includes sensing continuous signals andsensing pulsed signals repeatedly over a selected period time. Thecontinuously sensed signal may be used to continuously and/orautomatically adjust the drilling of wellbore 428B by drillbit 424. Thecontinuous sensing of the electromagnetic signal may be dual directionalso as to create a data link between transceivers. The antenna/sensor 432may be directly connected to a surface interface allowing a data linkbetween surface and subsurface to be established.

In some embodiments, source 436 and/or sensor 432 are sources andsensors used in a walkover radio locater system. Walkover radio locatersystems are, for example, used in telecommunications to locateunderground lines and to communicate the location to drilling tools usedfor utilities installation. Radio locater systems may be available, forexample, from Digital Control Incorporated (Kent, Wash., U.S.A.). Insome embodiments, the walkover radio located system components may bemodified to be located in wellbore 428A and wellbore 428B so that therelative positions of the wellbores are assessable using the walkoverradio located system components.

In certain embodiments, multiple sources and multiple sensors may beused to assess and adjust the drilling of one or more wellbores. FIG. 17depicts an embodiment for assessing a position of a plurality of firstwellbores relative to a plurality of second wellbores using radioranging signals. Sources 436 may be located in a plurality of wellbores428A. Sensors 432 may be located in one or more wellbores 428B. In someembodiments, sources 436 are located in wellbores 428B and sensors 432are located in wellbores 428A.

In one embodiment, wellbores 428A are drilled substantially verticallyin the formation and wellbores 428B are drilled substantiallyhorizontally in the formation. Thus, wellbores 428B are substantiallyperpendicular to wellbores 428A. Sensors 432 in wellbores 428B maydetect signals from one or more of sources 436. Detecting signals frommore than one source may allow for more accurate measurement of therelative positions of the wellbores in the formation. In someembodiments, electromagnetic attenuation and phase shift detected frommultiple sources is used to define the position of a sensor (and thewellbore). The paths of the electromagnetic radio waves may be predictedto allow detection and use of the electromagnetic attenuation and thephase shift to define the sensor position.

In certain embodiments, continuous pulsed signals and/or radio rangingsignals are used to form a plurality of wellbores in a formation. FIG.18 depicts a top view representation of an embodiment for forming aplurality of wellbores in a formation. Treatment area 816 may includeclusters of heaters 438 on opposite sides of the treatment area. Controlwellbore 428A may be located at or near the center line of treatmentarea 816. In certain embodiments, control wellbore 428A is located in abarrier area between heater corridors 1700A, 1700B. Control wellbore428A may be a horizontal, substantially horizontal, or slightly inclinedwellbore. Control wellbore 428A may have a length between about 250 mand about 3000 m, between about 500 m and about 2500 m, or between about1000 m and about 2000 m.

In certain embodiments, the position (lateral and/or vertical position)of control wellbore 428A in treatment area 816 is assessed relative tovertical wellbores 428B, 428C, of which the position is known. Therelative position to vertical wellbores 428B, 428C of control wellbore428A may be assessed using, for example, continuous pulsed signalsand/or radio ranging signals as described herein. In certainembodiments, vertical wellbores 428B, 428C are located within about 10m, within about 5 m, or within about 3 m of control wellbore 428A.

Heater wellbores 428D may be the first heater wellbores deployed ineither corridor 1700A or corridor 1700B. Ranging sources (for example,wire 434, depicted in FIG. 15, or source 436, depicted in FIGS. 16 and17) and/or sensors (for example, sensors 432, depicted in FIGS. 15-17)located in either heater wellbores 428D and/or control wellbore 428A maybe used to assess the positions (lateral and/or vertical) of the heaterwellbores relative to the control wellbore. In some embodiments, theranging systems are deployed inside a conduit provided into controlwellbore 428A. In some embodiments, control wellbore 428A acts as acurrent return for electrical current flowing from heater wellbores428D. Control wellbore 428A may include a steel casing or other metalelement that allows current to flow into the wellbore. The current maybe returned to the surface through control wellbore 428A to complete theelectrical circuit used for ranging (as shown by the dotted lines inFIG. 18).

In certain embodiments, the position of heater wellbores 428D arefurther assessed using ranging from vertical wellbores 428E. Assessingthe position of heater wellbores 428D relative to vertical wellbores428E may be used to verify position data from ranging from controlwellbore 428A. Vertical wellbores 428B, 428C, 428E may have depths thatare at least the depth of heater wellbores 428D and/or control wellbore428A. In certain embodiments, vertical wellbores 428E are located withinabout 10 m, within about 5 m, or within about 3 m of heater wellbores428D.

After heater wellbores 428D are formed in treatment area 816, additionalheater wellbores may be formed in corridor 1700A and/or corridor 1700B.The additional heater wellbores may be formed using heater wellbores428D and/or control wellbore 428A as guides. For example, rangingsystems may be located in heater wellbores 428D and/or control wellbore428A to assess and/or adjust the relative position of the additionalheater wellbores while the additional heater wellbores are being formed.

In some embodiments, central monitoring system 1702 is coupled tocontrol wellbore 428A. In certain embodiments, central monitoring system1702 includes a geomagnetic monitoring system. Central monitoring system1702 may be located at a known location relative to control wellbore428A and heater wellbores 428D. The known location may include knownalignment azimuths from control wellbore 428A. For example, the knownlocation may include north-south alignment azimuths, east-west alignmentazimuths, and any heater wellbore alignment azimuth that is intended forcorridor 1700A and/or corridor 1700B (for example, azimuths off the 90°angle depicted in FIG. 18). The geomagnetic monitoring system, alongwith the known location, may be used to calibrate individual tools usedduring formation of wellbores and ranging operations and/or to assessthe properties of components in bottom hole assemblies or other downholeassemblies.

FIGS. 19 and 20 depict an embodiment for assessing a position of a firstwellbore relative to a second wellbore using a heater assembly as acurrent conductor. In some embodiments, a heater may be used as a longconductor for a reference current (pulsed DC or AC) to be injected forassessing a position of a first wellbore relative to a second wellbore.If a current is injected onto an insulated internal heater element, thecurrent may pass to the end of heater element 438 where it makes contactwith heater casing 440. This is the same current path when the heater isin heating mode. Once the current passes across to bottom hole assembly420B, at least some of the current is generally absorbed by the earth onthe current's return trip back to the surface, resulting in a netcurrent (difference in Amps in (A_(i)) versus Amps out (A_(o)).

Resulting electromagnetic field 442 is measured by sensor 432 (forexample, a transceiving antenna) in bottom hole assembly 420A of firstwellbore 428A being drilled in proximity to the location of heater 438.A predetermined “known” net current in the formation may be relied uponto provide a reference magnetic field.

The injection of the reference current may be rapidly pulsed andsynchronized with the receiving antenna and/or sensor data. Access to ahigh data rate signal from the magnetometers can be used to filter theeffects of sensor movement during drilling. The measurement of thereference magnetic field may provide a distance and direction to theheater. Averaging many of these results will provide the position of theactively drilled hole. The known position of the heater and known depthof the active sensors may be used to assess position coordinates ofeasting, northing, and elevation.

The quality of data generated with such a method may depend on theaccuracy of the net current prediction along the length of the heater.Using formation resistivity data, a model may be used to predict thelosses to earth along the length of the heater canister and/or wellborecasing or wellbore liner.

The current may be measured on both the element and the bottom holeassembly at the surface. The difference in values is the overall currentloss to the formation. It is anticipated that the net field strengthwill vary along the length of the heater. The field is expected to begreater at the surface when the positive voltage applies to the bottomhole assembly.

If there are minimal losses to earth in the formation, the net field maynot be strong enough to provide a useful detection range. In someembodiments, a net current in the range of about 2 A to about 50 A,about 5 A to about 40 A, or about 10 A to about 30 A, may be employed.

In some embodiments, two or more heaters are used as a long conductorfor a reference current (pulsed DC or AC) to be injected for assessing aposition of a first wellbore relative to a second wellbore. Utilizingtwo or more separate heater elements may result in relatively bettercontrol of return current path and therefore better control of referencecurrent strength.

A two or more heater method may not rely on the accuracy of a “model ofcurrent loss to formation”, as current is contained in the heaterelement along the full length of the heaters. Current may be rapidlypulsed and synchronized with the transceiving antenna and/or sensor datato resolve distance and direction to the heater. FIGS. 21 and 22 depictan embodiment for assessing a position of first wellbore 428A relativeto second wellbore 428B using two heater assemblies 438A and 438B ascurrent conductors. Resulting electromagnetic field 442 is measured bysensor 432 (for example, a transceiving antenna) in bottom hole assembly420A of first wellbore 428A being drilled in proximity to the locationof heaters 438A in second wellbores 428B.

In some embodiments, parallel well tracking (PWT) may be used forassessing a position of a first wellbore relative to a second wellbore.Parallel well tracking may utilize magnets of a known strength and aknown length positioned in the pre-drilled second wellbore. Magneticsensors positioned in the active first wellbore may be used to measurethe field from the magnets in the second wellbore. Measuring thegenerated magnetic field in the second wellbore with sensors in thefirst wellbore may assess distance and direction of the active firstwellbore. In some embodiments, magnets positioned in the second wellboremay be carefully positioned and multiple static measurements taken toresolve any general “background” magnetic field. Background magneticfields may be resolved through use of a null function before positioningthe magnets in the second wellbore, calculating background componentsfrom known sensor attitudes, and/or a gradiometer setup.

In some embodiments, reference magnets may be positioned in the drillingbottom hole assembly of the first wellbore. Sensors may be positioned inthe passive second wellbore. The prepositioned sensors may be nulledprior to the arrival of the magnets in the detectable range to eliminateEarth's background field. Nulling the sensors may significantly reducethe time required to assess the position and direction of the firstwellbore during drilling as the bottom hole assembly continues drillingwith no stoppages. The commercial availability of low cost sensors suchas Terrella6™ (available from Clymer Technologies (Mystic, Conn.,U.S.A.) (utilizing magnetoresistives rather than fluxgates) may beincorporated into the wall of a deployment coil at useful separations.

In some embodiments, multiple types of sources may be used incombination with two or more sensors to assess and adjust the drillingof one or more wellbores. A method of assessing a position of a firstwellbore relative to a second wellbore may include a combination ofangle sensors, telemetry, and/or ranging systems. Such a method may bereferred to as umbilical position control.

Angle sensors may assess an attitude (i.e., the azimuth, inclination,and roll) of a bottom hole assembly. Assessing the attitude of a bottomhole assembly may include measuring, for example, azimuth, inclination,and/or roll. Telemetry may transmit data (for example, measurements)between the surface and, for example, sensors positioned in a wellbore.Ranging may assess the position of a bottom hole assembly in a firstwellbore relative to a second wellbore. In some embodiments, the secondwellbore may include an existing, previously drilled wellbore.

FIG. 23 depicts an embodiment of an umbilical positioning control systememploying a magnetic gradiometer system and wellbore to wellborewireless telemetry system. The magnetic gradiometer system may be usedto resolve bottom hole assembly interference. Second transceiver 444Bmay be deployed from the surface down second wellbore 428B, whicheffectively functions as a telemetry system for first wellbore 428A. Atransceiver may communicate with the surface via wire or fiber optics(for example, wire 446) coupled to the transceiver.

In first wellbore 428A, sensor 432A may be coupled to first transceivingantenna 444A. First transceiving antenna 444A may communicate withsecond transceiving antenna 444B in second wellbore 428B. The firsttransceiving antenna may be positioned on bottom hole assembly 420.Sensors coupled to the first transceiving antenna may include, forexample, magnetometers and/or accelerometers. In certain embodiments,sensors coupled to the first transceiving antenna may include dualmagnetometer/accelerometer sets.

To accomplish data transfer, first transceiving antenna 444A transmits(“short hops”) measured data through the ground to second transceivingantenna 444B located in the second wellbore. The data may then betransmitted to the surface via embedded wires 446 in the deploymenttubular. In some embodiments, data transmission to/from the surface isprovided through one or more data lines (wires) that previously exist inthe deployment tubular wellbore.

Two redundant ranging systems may be utilized for umbilical controlsystems. A first ranging system may include a version of parallel welltracking (PWT). FIG. 24 depicts an embodiment of an umbilicalpositioning control system employing a magnetic gradiometer system in anexisting wellbore. A PWT may include a pair of sensors 432B (forexample, magnetometer/accelerometer sets) embedded in the wall of secondwellbore deployment coil (the umbilical) or within a nonmagnetic sectionof jointed tubular string. These sensors act as a magnetic gradiometerto detect the magnetic field from reference magnet 430 installed inbottom hole assembly 420 of first wellbore 428A. In a horizontal sectionof the second wellbore, a relative position of the umbilical to thefirst wellbore reference magnet(s) may be determined by the gradient.Data may be sent to the surface through fiber optic cables or wires 446positioned in second wellbore 428B.

FIGS. 25 and 26 depict an embodiment of umbilical positioning controlsystem employing a combination of systems being used in a first stage ofdeployment and a second stage of deployment, respectively. A third setof sensors 432C (for example, magnetometers) may be located on theleading end of wire 446 in second wellbore 428B. Sensors 432B, 432C maydetect magnetic fields produced by reference magnets 430 in bottom holeassembly 420 of first wellbore 428A. The role of sensors 432C mayinclude mapping the Earth's magnetic field ahead of the arrival of thegradient sensors and confirming that the angle of the deployment tubularmatches that of the originally defined hole geometry. Since the attitudeof the magnetic field sensors are known based on the original survey ofthe hole and the checks of sensors 432B, 432C, the values for theEarth's field can be calculated based on current sensor orientation(inclinometers measure the roll and inclination and the model definesazimuth, Mag total, and Mag dip). Using this method, an estimation ofthe field vector due to reference magnets 430 can be calculated allowingdistance and direction to be resolved.

A second ranging system may be based on using the signal strength andphase of the “through the earth” wireless link (for example, radio)established between first transceiving antenna 444A in first wellbore428A and second transceiving antenna 444B in second wellbore 428B.Sensor 432A may be coupled to first transceiving antenna 444A. Given theclose spacing of wellbores 428A, 428B and the variability in electricalproperties of the formation, the attenuation rates for theelectromagnetic signal may be predictable. Predictable attenuation ratesfor the electromagnetic signal allow the signal strength to be used as ameasure of separation between first and second transceiver pairs 444A,444B. The vector direction of the magnetic field induced by theelectromagnetic transmissions from the first wellbore may provide thedirection. A transceiver may communicate with the surface via wire orfiber optics (for example, wire 446) coupled to the transceiver.

With a known resistivity of the formation and operating frequency, thedistance between the source and point of measurement may be calculated.FIG. 27 depicts two examples of the relationship between power receivedand distance based upon two different formations with differentresistivities 448 and 450. If 10 W is transmitted at a 12 Hz frequencyin 20 ohm-m formation 448, the power received amounts to approximately9.10 W at 30 m distance. The resistivity was chosen at random and mayvary depending on where you are in the ground. If a higher resistivitywas chosen at the given frequency, such as 100 ohm-m formation 450, alower attenuation is observed, and a low characterization occurswhereupon it receives 9.58 W at 30 m distance. Thus, high resistivity,although transmitting power desirably, shows a negative affect inelectromagnetic ranging possibilities. Since the main influence inattenuation is the distance itself, calculations may be made solving forthe distance between a source and a point of measurement.

The frequency of the electromagnetic source operates on is anotherfactor that affects attenuation. Typically, the higher the frequency,the higher the attenuation and vice versa. A strategy for choosingbetween various frequencies may depend on the formation chosen. Forexample, while the attenuation at a resistivity of 100 ohm-m may be goodfor data communications, it may not be sufficient for distancecalculations. Thus, a higher frequency may be chosen to increaseattenuation. Alternatively, a lower frequency may be chosen for theopposite purpose. In some embodiments, a combination of differentfrequencies is used in sequence to optimize for both low and highfrequency functions.

Wireless data communications in ground may allow an opportunity forelectromagnetic ranging and the variable frequency it operates on mustbe observed to balance out benefits for both functionalities. Benefitsof wireless data communication may include, but are not be limitedto: 1) automatic depth sync through the use of ranging and telemetry; 2)fast communications with a dedicated coil for a transceiving antennarunning in the second wellbore that is hardwired (for example, withoptic fiber); 3) functioning as an alternative method for fastcommunication when hardwire in the first wellbore is not available; 4)functioning in under balanced and over balanced drilling; 5) providing asimilar method for transmitting control commands to a bottom holeassembly; 6) reusing sensors to reduce costs and waste; 7) decreasingnoise measurement functions split between the first wellbore and thesecond wellbore; and/or 8) using simultaneous multiple positionmeasurement techniques to provide real time best estimates of positionand attitude.

In some embodiments, it may be advisable to employ sensors able tocompensate for magnetic fields produced internally by carbon steelcasing built in the vertical section of a reference hole (for example,high range magnetometers). In some embodiments, modification may be madeto account for problems with wireless antenna communications betweenwellbores penetrating through wellbore casings.

Pieces of formation or rock may protrude or fall into the wellbore dueto various failures including rock breakage or plastic deformationduring and/or after wellbore formation. Protrusions may interfere withdrilling string movement and/or the flow of drilling fluids. Protrusionsmay prevent running tubulars into the wellbore after the drilling stringhas been removed from the wellbore. Significant amounts of materialentering or protruding into the wellbore may cause wellbore integrityfailure and/or lead to the drilling string becoming stuck in thewellbore. Some causes of wellbore integrity failure may be in situstresses and high pore pressures. Mud weight may be increased to holdback the formation and inhibit wellbore integrity failure duringwellbore formation. When increasing the mud weight is not practical, thewellbore may be reamed.

Reaming the wellbore may be accomplished by moving the drilling stringup and down one joint while rotating and circulating. Picking thedrilling string up can be difficult because of material protruding intothe borehole above the bit or BHA (bottom hole assembly). Picking up thedrilling string may be facilitated by placing upward facing cuttingstructures on the drill bit. Without upward facing cutting structures onthe drill bit, the rock protruding into the borehole above the drill bitmust be broken by grinding or crushing rather than by cutting. Grindingor crushing may induce additional wellbore failure.

Moving the drilling string up and down may induce surging or pressurepulses that contribute to wellbore failure. Pressure surging orfluctuations may be aggravated or made worse by blockage of normaldrilling fluid flow by protrusions into the wellbore. Thus, attempts toclear the borehole of debris may cause even more debris to enter thewellbore.

When the wellbore fails further up the drilling string than one jointfrom the drill bit, the drilling string must be raised more than onejoint. Lifting more than one joint in length may require that joints beremoved from the drilling string during lifting and placed back on thedrilling string when lowered. Removing and adding joints requiresadditional time and labor, and increases the risk of surging ascirculation is stopped and started for each joint connection.

In some embodiments, cutting structures may be positioned at variouspoints along the drilling string. Cutting structures may be positionedon the drilling string at selected locations, for example, where thediameter of the drilling string or BHA changes. FIG. 28A and FIG. 28Bdepict cutting structures 452 located at or near diameter changes indrilling string 418 near to drill bit 424 and/or BHA 420. As depicted inFIG. 28C, cutting structures 452 may be positioned at selected locationsalong the length of BHA 420 and/or drilling string 418 that has asubstantially uniform diameter. Cutting structures 452 may removeformation that extends into the wellbore as the drilling string isrotated. Cuttings formed by the cutting structures 452 may be removedfrom the wellbore by the normal circulation used during the formation ofthe wellbore.

FIG. 29 depicts an embodiment of drill bit 424 including cuttingstructures 452. Drill bit 424 includes downward facing cuttingstructures 452 b for forming the wellbore. Cutting structures 452 a areupwardly facing cutting structures for reaming out the wellbore toremove protrusions from the wellbore.

In some embodiments, some cutting structures may be upwardly facing,some cutting structures may be downwardly facing, and/or some cuttingstructures may be oriented substantially perpendicular to the drillingstring. FIG. 30 depicts an embodiment of a portion of drilling string418 including upward facing cutting structures 452 a, downward facingcutting structures 452 b, and cutting structures 452 c that aresubstantially perpendicular to the drilling string. Cutting structures452 a may remove protrusions extending into wellbore 428 that wouldinhibit upward movement of drilling string 418. Cutting structures 452 amay facilitate reaming of wellbore 428 and/or removal of drilling string418 from the wellbore for drill bit change, BHA maintenance and/or whentotal depth has been reached. Cutting structures 452 b may removeprotrusions extending into wellbore 428 that would inhibit downwardmovement of drilling string 418. Cutting structures 452 c may ensurethat enlarged diameter portions of drilling string 418 do not becomestuck in wellbore 428.

Positioning downward facing cutting structures 452 b at variouslocations along a length of the drilling string may allow for reaming ofthe wellbore while the drill bit forms additional borehole at the bottomof the wellbore. The ability to ream while drilling may avoid pressuresurges in the wellbore caused by lifting the drilling string. Reamingwhile drilling allows the wellbore to be reamed without interruptingnormal drilling operation. Reaming while drilling allows the wellbore tobe formed in less time because a separate reaming operation is avoided.Upward facing cutting structures 452 a allow for easy removal of thedrilling string from the wellbore.

In some embodiments, the drilling string includes a plurality of cuttingstructures positioned along the length of the drilling string, but notnecessarily along the entire length of the drilling string. The cuttingstructures may be positioned at regular or irregular intervals along thelength of the drilling string. Positioning cutting structures along thelength of the drilling string allows the entire wellbore to be reamedwithout the need to remove the entire drilling string from the wellbore.

Cutting structures may be coupled or attached to the drilling stringusing techniques known in the art (for example, by welding). In someembodiments, cutting structures are formed as part of a hinged ring ormulti-piece ring that may be bolted, welded, or otherwise attached tothe drilling string. In some embodiments, the distance that the cuttingstructures extend beyond the drilling string may be adjustable. Forexample, the cutting element of the cutting structure may includethreading and a locking ring that allows for positioning and setting ofthe cutting element.

In some wellbores, a wash over or over-coring operation may be needed tofree or recover an object in the wellbore that is stuck in the wellboredue to caving, closing, or squeezing of the formation around the object.The object may be a canister, tool, drilling string, or other item. Awash-over pipe with downward facing cutting structures at the bottom ofthe pipe may be used. The wash over pipe may also include upward facingcutting structures and downward facing cutting structures at locationsnear the end of the wash-over pipe. The additional upward facing cuttingstructures and downward facing cutting structures may facilitate freeingand/or recovery of the object stuck in the wellbore. The formationholding the object may be cut away rather than broken by relying onhydraulics and force to break the portion of the formation holding thestuck object.

A problem in some formations is that the formed borehole begins to closesoon after the drilling string is removed from the borehole. Boreholeswhich close up soon after being formed make it difficult to insertobjects such as tubulars, canisters, tools, or other equipment into thewellbore. In some embodiments, reaming while drilling applied to thecore drilling string allows for emplacement of the objects in the centerof the core drill pipe. The core drill pipe includes one or more upwardfacing cutting structures in addition to cutting structures located atthe end of the core drill pipe. The core drill pipe may be used to formthe wellbore for the object to be inserted in the formation. The objectmay be positioned in the core of the core drill pipe. Then, the coredrill pipe may be removed from the formation. Any parts of the formationthat may inhibit removal of the core drill pipe are cut by the upwardfacing cutting structures as the core drill pipe is removed from theformation.

Replacement canisters may be positioned in the formation using over coredrill pipe. First, the existing canister to be replaced is over cored.The existing canister is then pulled from within the core drill pipewithout removing the core drill pipe from the borehole. The replacementcanister is then run inside of the core drill pipe. Then, the core drillpipe is removed from the borehole. Upward facing cutting structurespositioned along the length of the core drill pipe cut portions of theformation that may inhibit removal of the core drill pipe.

During some in situ heat treatment processes, wellbores may need to beformed in heated formations. Wellbores may also need to be formed in hotportions of geothermally heated or other high temperature formations.Certain formations may be heated by heat sources (for example, heaters)to temperatures above ambient temperatures of the formations. In someembodiments, formations are heated to temperatures significantly aboveambient temperatures of the formations. For example, a formation may beheated to a temperature at least about 50° C. above ambient temperature,at least about 100° C. above ambient temperature, at least about 200° C.above ambient temperature, or at least about 500° C. above ambienttemperature. Wellbores drilled into hot formation may be additional orreplacement heater wells, additional or replacement production wells,and/or monitor wells.

Cooling while drilling may enhance wellbore stability, safety, andlongevity of drilling tools. When the drilling fluid is liquid,significant wellbore cooling can occur due to the circulation of thedrilling fluid. Downhole cooling does not have to be applied all the wayto the bottom of the wellbore to have beneficial effects. Applyingcooling to only part of the drilling string and/or downhole equipmentmay be a trade off between benefit and the effort involved to apply thecooling to the drilling string and downhole equipment. The target of thecooling may be the formation, the drill bit, and/or the bottom holeassembly. In some embodiments, cooling of the formation is inhibited topromote wellbore stability. Cooling of the formation may be inhibited byusing insulation to inhibit heat transfer from the formation to thedrilling string, bottom hole assembly, and/or the drill bit. In someembodiments, insulation is used to inhibit heat transfer and/or phasechanges of drilling fluid and/or cooling fluid in portions of thedrilling string, bottom hole assembly, and/or the drill bit.

In some in situ heat treatment process embodiments, a barrier formedaround all or a portion of the in situ heat treatment process is formedby freeze wells that form a low temperature zone around the freezewells. A portion of the cooling capacity of the freeze well equipmentmay be utilized to cool the equipment needed to drill into the hotformation. A closed loop circulation system may be used to cool drillingbits and/or other downhole equipment. Drilling bits may be advancedslowly in hot sections to ensure that the formed wellbore coolssufficiently to preclude drilling problems and/or to enhance boreholestability.

When using conventional circulation, drilling fluid flows down theinside of the drilling string and back up the outside of the drillingstring. Other circulation systems, such as reverse circulation, may alsobe used. In some embodiments, the drill pipe may be positioned in apipe-in-pipe configuration, or a pipe-in-pipe-in-pipe configuration (forexample, when a closed loop circulation system is used to cool downholeequipment).

The drilling string used to form the wellbore may function as acounter-flow heat exchanger. The deeper the well, the more the drillingfluid heats up on the way down to the drill bit as the drilling stringpasses through heated portions of the formation. When normal circulationdoes not deliver low enough temperatures drilling fluid to the drill bitto provide adequate cooling, two options may be employed to enhancecooling: mud coolers on the surface can be used to reduce the inlettemperature of the drilling fluid being pumped downhole; and, if coolingis still inadequate, an at least partially insulated drilling string canbe used to reduce the counter-flow heat exchanger effect.

For various reasons including, but not limited to, lost circulation,wells are frequently drilled with gas (for example, air, nitrogen,carbon dioxide, methane, ethane, and other light hydrocarbon gases) orgas/liquid mixtures. Gas/liquid mixtures are used as the drilling fluidprimarily to maintain a low equivalent circulating density (low downholepressure gradient). Gas has low potential for cooling the wellborebecause mass flow rates of gas drilling are much lower than when liquiddrilling fluid is used. Also, gas has a low heat capacity compared toliquid. As a result of heat flow from the outside to the inside of thedrilling string, the gas arrives at the drill bit at close to formationtemperature. Controlling the inlet temperature of the gas (analogous tousing mud coolers when drilling with liquid) or using insulated drillingstring may marginally reduce the counter-flow heat exchanger effect whengas drilling. Some gases are more effective than others at transferringheat, but the use of gasses with better heat transfer properties may notsignificantly improve wellbore cooling while gas drilling.

Gas drilling may deliver the drilling fluid to the drill bit at close tothe formation temperature. The gas may have little capacity to absorbheat. A feature of gas drilling is the low density column in theannulus. The benefits of gas drilling can be accomplished if thedrilling fluid or a cooling fluid is liquid while flowing down thedrilling string and gas while flowing back up the annulus. The heat ofvaporization may be used to cool the drill bit and the formation ratherthan using the sensible heat of the drilling fluid to cool.

An advantage of this approach may be that even though the liquid arrivesat the bit at close to formation temperature, the liquid can absorb heatby vaporizing. The heat of vaporization is typically larger than theheat that can be absorbed by a temperature rise. As a comparison, a 7⅞″wellbore is drilled with a 3½″ drilling string circulating low densitymud at about 203 gpm with about a 100 ft/min typical annular velocity.Drilling through a 450° F. zone at 1000 feet will result in a mud exittemperature about 8° F. hotter than the inlet temperature. This resultsin the removal of about 14,000 Btu/min. The removal of this heat lowersthe bit temperature from about 450° F. to about 285° F. If liquid wateris injected down the drilling string and allowed to boil at the bit andsteam is produced up the annulus, the mass flow required to remove ½″cuttings is about 34 lb_(m)/min assuming the back pressure is about 100psia. At 34 lb_(m)/min, the heat removed from the wellbore would beabout 34 lb_(m)/min×(1187-180) Btu/lb_(m), or about 34,000 Btu/min. Thisheat removal amount is about 2.4 times the liquid cooling case. Thus, atreasonable annular steam flow rates, a significant amount of heat may beremoved by vaporization.

The high velocities required for gas drilling may be achieved by theexpansion that occurs during vaporization rather than by employingcompressors on the surface. Eliminating or minimizing the need forcompressors may simplify the drilling process, eliminate or lowercompression costs, and eliminate or reduce a source of heat applied tothe drilling fluid on the way to the drill bit.

In some embodiments, it is helpful to inhibit vaporization within thedrilling string. If the drilling fluid flowing downwards vaporizesbefore reaching the drill bit, the heat of vaporization tends to extractheat from the drilling fluid flowing up the annulus. The heattransferred from the annulus (outside the drilling string) to inside thedrilling string is heat that is not rejected from the well when drillingfluid reaches the surface. Vaporization that occurs inside of thedrilling string before the drilling fluid reaches the bottom of the holeis less beneficial to drill bit and/or wellbore cooling. FIG. 31 depictsdrilling fluid flow in drilling string 418 in wellbore 428 with nocontrol of vaporization of the fluid. Liquid drilling fluid flows downdrilling string 418 as indicated by arrow 1704. Liquid changes to vaporat interface 1706. Vapor flows down drilling string 418 below interface1706 as indicated by arrow 1708. In certain embodiments, interface 1706is a region instead of an abrupt change from liquid to vapor. Vapor andcuttings may flow up the annular region between drilling string 418 andformation 524 in the directions indicated by arrows 1710. Heat transfersfrom formation 524 to the vapor moving up drilling string 418 and to thedrilling string. Heat from drilling string 418 transfers to liquid andvapor flowing down the drilling string.

If the pressure in the drilling string is maintained above the boilingpressure for a given temperature by use of a back pressure device, thenthe transfer of heat from outside the drilling string to fluid on theinside of the drilling string can be limited so that the fluid on theinside of the drilling string does not change phases. Fluid downstreamof the back pressure device may be allowed to change phase. The fluiddownstream the back pressure device may be partially or totallyvaporized. Vaporization may result in the drilling fluid absorbing theheat of vaporization from the drill bit and formation. For example, ifthe back pressure device is set to allow flow only when the backpressure is above a selected pressure (for example, 250 psi for water oranother pressure depending on the fluid), the fluid within the drillingstring may not vaporize unless the temperature is above a selectedtemperature (for example, 400° F. for water or another temperaturedepending on the fluid). If the temperature of the formation is abovethe selected temperature (for example, the temperature is about 500°F.), steps may be taken to inhibit vaporization of the fluid on the waydown to the drill bit. In an embodiment, the back pressure device is setto maintain a back pressure that inhibits vaporization of the drillingfluid at the temperature of the formation (for example, 580 psi toinhibit vaporization up to a temperature of 500° F. for water). Inanother embodiment, the drilling pipe is insulated and/or the drillingfluid is cooled so that the back pressure device is able to maintain anydrilling fluid that reaches the drill bit as a liquid.

Examples of two back pressure devices that may be used to maintainelevated pressure within the drilling string are a choke and a pressureactivated valve. Other types of back pressure devices may also be used.Chokes have a restriction in the flow area that creates back pressure byresisting flow. Resisting the flow results in increased upstreampressure to force the fluid through the restriction. Pressure activatedvalves may not open until a minimum upstream pressure is obtained. Thepressure difference across a pressure activated valve may determine ifthe pressure activated valve is open to allow flow or the valve isclosed.

In some embodiments, both a choke and a pressure activated valve may beused. A choke can be the bit nozzles allowing the liquid to be jettedtoward the drill bit and the bottom of the hole. The bit nozzles mayenhance drill bit cleaning and help inhibit fouling of the drill bit andpressure activated valve. Fouling may occur if boiling in the drill bitor pressure activated valve causes solids to precipitate. The pressureactivated valve may inhibit premature vaporization at low flow ratessuch as flow rates below which the chokes are effective.

In some embodiments, additives are added to the cooling fluid or thedrilling fluid. The additives may modify the properties of the fluids inthe liquid phase and/or the gas phase. Additives may include, but arenot limited to, surfactants to foam the fluid, additives to chemicallyalter the interaction of the fluid with the formations (for example, tostabilize the formation), additives to control corrosion, and additivesfor other benefits.

In some embodiments, a non-condensable gas is added to the cooling fluidor the drilling fluid pumped down the drilling string. Thenon-condensable gas may be, but is not limited to, nitrogen, carbondioxide, air, and mixtures thereof. Adding the non-condensable gasresults in pumping a two phase mixture down the drilling string. Onereason for adding the non-condensable gas may be to enhance the flow ofthe fluid out of the formation. The presence of the non-condensable gasmay inhibit condensation of the vaporized cooling or drilling fluidand/or help to carry cuttings out of the formation. In some embodiments,one or more heaters are present at one or more locations in the wellboreto provide heat that inhibits condensation and reflux of cooling ordrilling fluid leaving the formation.

In certain embodiments, managed pressure drilling and/or managedvolumetric drilling is used during the formation of wellbores. The backpressure on the wellbore may be held to a prescribed value to controlthe downhole pressure. Similarly, the volume of fluid entering andexiting the wellbore may be balanced such that there is no or minimallycontrolled net influx or out-flux of drilling fluid into the formation.

FIG. 32 depicts a representation of a system for forming wellbore 428 inheated formation 524. Liquid drilling fluid flows down the drillingstring to bottom hole assembly 420 in the direction indicated by arrow1704. Bottom hole assembly 420 may include back pressure device 1712.Back pressure device 1712 may include pressure activated valves and/orchokes. In some embodiments, back pressure device 1712 is adjustable.Back pressure device 1712 may be electrically coupled to bottom holeassembly 420. The control system for bottom hole assembly 420 maycontrol the inlet flow of cooling or drilling fluid and may adjust theamount of flow through back pressure device 1712 to maintain thepressure of cooling or drilling fluid located above the back pressuredevice above a desired pressure. Thus, back pressure device 1712 may beoperated to control vaporization of the cooling fluid. In certainembodiments, back pressure device 1712 includes a control volume. Insome embodiments, the control volume is a conduit that carries thecooling fluid to bottom hole assembly 420.

The desired pressure may be a pressure sufficient to maintain cooling ordrilling fluid as a liquid phase to cool drill bit 424 when the liquidphase of the cooling or drilling fluid is vaporized. At least a portionof the liquid phase of the cooling or drilling fluid may vaporize andabsorb heat from drill bit 424. In certain embodiments, vaporization ofthe cooling fluid is controlled to control a temperature at or nearbottom hole assembly 420. In some embodiments, bottom hole assembly 420includes insulation to inhibit heat transfer from the formation to thebottom hole assembly. In some embodiments, drill bit 424 includes aconduit for flow of the cooling fluid. Vapor phase cooling or drillingfluid and cuttings may flow upwards to the surface in the directionindicated by arrow 1710.

In some embodiments, cooling fluid in a closed loop is circulated intoand out of the wellbore to provide cooling to the formation, drillingstring, and/or downhole equipment. In some embodiments, phase change ofthe cooling fluid is not utilized during cooling. In some embodiments,the cooling fluid is subjected to a phase change to cool the formation,drilling string, and/or downhole equipment.

In an embodiment, cooling fluid in a closed loop system is passedthrough a back pressure device and allowed to vaporize to providecooling to a selected region. FIG. 33 depicts a representation of asystem that uses phase change of a cooling fluid to provide downholecooling. Drilling fluid may flow down the center drilling string todrill bit 424 in the direction indicated by arrow 1704. Return drillingfluid and cuttings may flow to the surface in the direction indicated byarrows 1710. Cooling fluid may flow down the annular region betweencenter drilling string and the middle drilling string in the directionindicated by arrows 1718. The cooling fluid may pass through backpressure device 1712 to a vaporization chamber. The vaporization chambermay be located above the bottom hole assembly. Back pressure device 1712may maintain a significant portion of cooling fluid in a liquid phaseabove the back pressure device. Cooling fluid is allowed to vaporizebelow back pressure device 1712 in the vaporization chamber. In certainembodiments, at least a majority of the cooling fluid is vaporized.Return vaporized cooling fluid may flow back to a cooling system thatreliquefies the cooling fluid for subsequent usage in the drillingstring and/or another drilling string. The vaporized cooling fluid mayflow to the surface in the annular region between the middle drillingstring and the outer drilling string in the direction indicated byarrows 1720. Liquid cooling fluid may maintain the drilling fluidflowing through the center drilling string at a temperature below theboiling temperature of the cooling fluid.

FIG. 34 depicts a representation of a system for forming wellbore 428 inheated formation 524 using reverse circulation. Drilling fluid flowsdown the annular region between formation 524 and outer drilling string418 in the direction indicated by arrows 1714. Drilling fluid andcuttings pass through drill bit 424 and up center drilling string 418′in the direction indicated by arrow 1716. Cooling fluid may flow downthe annular region between outer drilling string 418 and center drillingstring 418′ in the direction indicated by arrows 1718. The cooling fluidmay be water or another type of cooling fluid that is able to changefrom a liquid phase to a vapor phase and absorb heat. The cooling fluidmay flow to back pressure device 1712. Back pressure device 1712 maymaintain the pressure of the cooling fluid located above the backpressure device above a pressure sufficient to maintain the coolingfluid as a liquid phase to cool drill bit 424 when the liquid phase ofthe drilling fluid is vaporized. Cooling fluid may pass through backpressure device 1712 into vaporization chamber 1722. Vaporization ofcooling fluid may absorb heat from drill bit 424 and/or from formation524. Vaporized cooling fluid may pass through one or more lift valvesinto center drilling string 418′ to help transport drilling fluid andcuttings to the surface.

In some embodiments, an auto-positioning control system in combinationwith a rack and pinion drilling system may be used for forming wellboresin a formation. Use of an auto-positioning control and/or measurementsystem in combination with a rack and pinion drilling system may allowwellbores to be drilled more accurately than drilling using manualpositioning and calibration. For example, the auto-positioning systemmay be continuously and/or semi-continuously calibrated during drilling.FIG. 35 depicts a schematic of a portion of a system including a rackand pinion drive system. Rack and pinion drive system 1724 includes, butis not limited to, rack 1728, carriage 1764, chuck drive system 1730,and circulating sleeve 1748. Chuck drive system 1730 may hold tubular1734. Push/pull capacity of a rack and pinion type system may allowenough force (for example, about 5 tons) to push tubulars into wellboresso that rotation of the tubulars is not necessary. A rack and pinionsystem may apply downward force on the drill bit. The force applied tothe drill bit may be independent of the weight of the drilling stringand/or collars. In certain embodiments, collar size and weight isreduced because the weight of the collars is not needed to enabledrilling operations. Drilling wellbores with long horizontal portionsmay be performed using rack and pinion drilling systems because of theability of the drilling systems to apply force to the drilling bit.

Rack and pinion drive system 1724 may be coupled to auto-positioningcontrol system 1766. Auto-positioning control system 1766 may include,but is not limited to, rotary steerable systems, dual motor rotarysteerable systems, and/or hole measurement systems. In some embodiments,heaters are included in tubular 1734. In some embodiments,auto-positioning measurement tools are positioned in the heaters. Insome embodiments, a measurement system includes magnetic ranging and/ora non-rotating sensor.

In some embodiments, a hole measuring system includes cantedaccelerometers. Use of canted accelerometers may allow for surveying ofa shallow portion of the formation. For example, shallow portions of theformation may have steel casing strings from drilling operations and/orother wells. The steel casings may affect the use of magnetic surveytools in determining the direction of deflection incurred duringdrilling. Canted accelerometers may be positioned in a bottom holeassembly with the surface as reference of string rotational position.Positioning the canted accelerometers in a bottom hole assembly mayallow accurate measurement of inclination and direction of a holeregardless of the influence of nearby magnetic interference sources (forexample, casing strings). In some embodiments, the relative rotationalposition of the tubular is monitored by measuring and trackingincremental rotation of the shaft. By monitoring the relative rotationof tubulars added to existing tubulars, more accurate positioning oftubulars may be achieved. Such monitoring may allow tubulars to be addedin a continuous manner. In some embodiments, a method of drilling usinga rack and pinion system includes continuous downhole measurement. Ameasurement system may be operated using a predetermined and constantcurrent signal. Distance and direction are calculated continuouslydownhole. The results of the calculations are filtered and averaged. Abest estimate final distance and direction is reported to the surface.When received on surface, the known along hole depth and source locationmay be combined with the calculated distance and direction to calculateX, Y & Z position data.

During drilling with jointed pipes, the time taken to shut downcirculation, add the next pipe, re-establish circulation, and holemaking may require a substantial amount of time, particularly when usingtwo-phase circulation. Handling tubulars (for example, pipes) hashistorically been a key safety risk area where manual handlingtechniques have been used. Coiled tubing drilling has had some successin eliminating the need for making connections and manual tubularhandling, however, the inability to rotate and the limitations onpractical coil diameters may limit the extent to which it can be used.

In some embodiments, a drilling sequence is used in which tubulars areadded to a string without interrupting the drilling process. Such asequence may allow continuous rotary drilling with large diametertubulars. A continuous rotary drilling system may include a drillingplatform, which includes, but is not limited to, one or more platforms,a top drive system, and a bottom drive system. The platform may includea rack to allow multiple independent traversing of components. The topdrive system may include an extended drive sub (for example, an extendeddrive system manufactured by American Augers, West Salem, Ohio, U.S.A.).The bottom drive system may include a chuck drive system and a hydraulicsystem. The bottom drive system may operate in a similar manner to arack and pinion drilling system. The chuck drive system may be mountedon a separate carriage. The hydraulic system may include, but is notlimited to, one or more motors and a circulating sleeve. The circulatingsleeve may allow circulation between tubulars and the annulus. Thecirculating sleeve may be used to open or shut off production fromvarious intervals in the well. In some embodiments, a system includes atubular handling system. A tubular handling system may be automated,manually operated, or a combination thereof.

FIGS. 36A-36D depict a schematic of an illustrative continuous drillingsequence. The system used to carry out the continuous drilling sequenceincludes bottom drive system 1738, tubular handling system 1740, and topdrive system 1742. Top drive system 1742 includes circulating sleeve1744 and drive sub 1758. Top drive system 1740 may be, for example, arotary drive system or a rack and pinion drive system. Bottom drivesystem 1738 includes circulating sleeve 1748 and chuck 1762. Forexample, bottom drive system 1738 may be a rack and pinion type systemsuch as depicted in FIG. 35. In some embodiments, the chuck may be on aseparate carriage system. During the sequence, new tubulars (forexample, new tubular 1736) may be coupled successively, one afteranother, to an existing tubular (for example, existing tubular 1734).Bottom drive system 1738 and top drive system 1742 may alternate controlof the drilling operation.

As the sequence commences, existing tubular 1734 is coupled to chuck1762, and bottom drive system 1738 controls drilling. Fluid may flowthrough port 1750 into circulating sleeve 1748 of bottom drive system1738. Top drive system 1742 is at reference line Y and bottom drivesystem 1738 is at reference line Z. It will be understood that referencelines Y and Z are shown for illustrative purposes only, and the heightsof the drive systems at various stages in the sequence may be differentthan those depicted in FIGS. 36A-36D. As shown in FIG. 36A, new tubular1736 may be aligned with bottom drive system 1738 using tubular handlingsystem 1740. Once in position, top drive system 1742 may be connected toa top end (for example, a box end) of new tubular 1736.

As shown in FIG. 36B, as chuck 1762 of bottom drive system 1738continues to control drilling, top drive system 1742 lowers andpositions or drops a bottom end of new tubular 1736 in circulatingsleeve 1748 (see arrows). Once new tubular 1736 is in the chamber ofcirculating sleeve 1748, circulation changes to top drive system 1742and a connection is made between new tubular 1736 and existing tubular1734. After the connection between existing tubular 1734 and new tubular1736 is made, bottom drive system 1738 may relinquish control of thedrilling process to top drive system 1742. Fluid flows through port 1746into circulating sleeve 1744 of top drive system 1742.

As shown in FIG. 36C, with top drive system 1742 controlling thedrilling process, bottom drive system 1738 may be actuated to travelupward (see arrow) toward top drive system 1742 along the length of newtubular 1736. When bottom drive system 1738 reaches the top of newtubular 1736, the new tubular may be engaged with chuck 1762 of bottomdrive system 1738. Top drive system 1742 may relinquish control of thedrilling process to bottom drive system 1738. Bottom drive system 1738may resume control of the drilling operation while top drive system 1742disconnects from the new tubular 1736. Chuck 1762 may transfer force tonew tubular 1736 to continue drilling. Top drive system 1742 may beraised relative to bottom drive system 1738 (see arrow) (for example,until top drive system 1742 reaches reference line Y). As shown in FIG.36D, bottom drive system 1738 may be lowered to push new tubular 1736and existing tubular 1734 downward into the formation (see arrows).Bottom drive system 1738 may continue to be lowered (for example, untilbottom drive system 1738 has returned to reference line Z). The sequencedescribed above may be repeated any number of times so as to maintaincontinuous drilling operations.

FIG. 37 depicts a schematic of an embodiment of circulating sleeve 1748.Fluid may enter circulating sleeve 1748 through port 1750 and flowaround existing tubular 1734. Fluid may remove heat away from chuck 1762and/or tubulars. Circulating sleeve 1748 includes opening 1752. Opening1752 allows new tubular 1736 to enter circulating sleeve 1748 so thatthe new tubular may be coupled to existing tubular 1734. In someembodiments, a valve is provided at opening 1752. For example, the valvemay be a UBD circulation valve. Opening 1752 may include one or moretooljoints 1754. Tooljoints 1754 may guide entry of new tubular 1736 inan inner section of circulating sleeve. As new tubular 1736 entersopening 1752 of circulating sleeve 1748, fluid flow through thecirculating sleeve may be under pressure. For example, fluid through thecirculating sleeve may be at pressures of up to about 13.8 MPa (up toabout 2000 psi).

In some embodiments, circulating sleeve 1748 may include, and/or operatein conjunction with, one or more valves. FIG. 38 depicts a schematic ofsystem including circulating sleeve 1748, side valve 1756, and top valve1760. Side valve 1756 may be a check valve incorporated into a sideentry flow and check valve port. Top entry valve 1760 may be a checkvalve. Use of check valves may facilitate change of circulation entrypoints and creation of a seal.

As circulating system sleeve 1748 comes into proximity with drive sub1758 (as described in FIG. 36D), fluid from top drive system 1742 may beflowing from circulating sleeve 1744 of top drive system 1742 throughtop valve 1760. Circulating sleeve 1748 may be pressurized and sidevalve 1756 may open to provide flow. Top valve 1760 may shut and/orpartially close as side valve 1756 opens to provide flow to circulatingsleeve 1744. Circulation may be slowed or discontinued through top drivesystem 1742. As circulation is stopped through top drive system 1742,top valve 1760 may close completely and all fluid may be furnishedthrough side valve 1756 from port 1750.

In some embodiments, one piece of equipment may be used to drillmultiple wellbores in a single day. The wellbores may be formed atpenetration rates that are many times faster than the penetration ratesusing conventional drilling with drilling bits. The high penetrationrate allows separate equipment to accomplish drilling and casingoperations in a more efficient manner than using a one-rig approach. Thehigh penetration rate requires accurate, near real time directionaldrilling control in three dimensions.

In some embodiments, high penetration rates may be attained usingcomposite coiled tubing in combination with particle jet drilling.Particle jet drilling forms an opening in a formation by impacting theformation with high velocity fluid containing particles to removematerial from the formation. The particles may function as abrasives. Inaddition to composite coiled tubing and particle jet drilling, adownhole electric orienter, bubble entrained mud, downhole inertialnavigation, and a computer control system may be needed. Other types ofdrilling fluid and drilling fluid systems may be used instead of usingbubble entrained mud. Such drilling fluid systems may include, but arenot limited to, straight liquid circulation systems, multiphasecirculation systems using liquid and gas, and/or foam circulationsystems.

Composite coiled tubing has a fatigue life that is significantly greaterthan the fatigue life of steel coiled tubing. Composite coiled tubing isavailable from Airborne Composites BV (The Hague, The Netherlands).Composite coiled tubing can be used to form many boreholes in aformation. The composite coiled tubing may include integral power linesfor providing electricity to downhole tools. The composite coiled tubingmay include integral data lines for providing real time informationregarding downhole conditions to the computer control system and forsending real time control information from the computer control systemto the downhole equipment. The primary computer control system may bedownhole or may be at surface.

The coiled tubing may include an abrasion resistant outer sheath. Theouter sheath may inhibit damage to the coiled tubing due to slidingexperienced by the coiled tubing during deployment and retrieval. Insome embodiments, the coiled tubing may be rotated during use in lieu ofor in addition to having an abrasion resistant outer sheath to minimizeuneven wear of the composite coiled tubing.

Particle jet drilling may advantageously allow for stepped changes inthe drilling rate. Drill bits are no longer needed and downhole motorsare eliminated. Particle jet drilling may decouple cutting formation toform the borehole from the bottom hole assembly (BHA). Decouplingcutting formation to form the borehole from the BHA reduces the impactthat variable formation properties (for example, formation dip, vugs,fractures and transition zones) have on wellbore trajectory. Thedecoupling lowers the required torque and thrust that would normally berequired if conventional drilling bits were used to form a borehole inthe formation. By decoupling cutting formation to form the borehole fromthe BHA, directional drilling may be reduced to orienting one or moreparticle jet nozzles in appropriate directions. The orientation of theBHA becomes easier with the reduced torque on the assembly from the holemaking process. Additionally, particle jet drilling may be used to underream one or more portions of a wellbore to form a larger diameteropening.

Particles may be introduced into a pressurized injection stream duringparticle jet drilling. The ability to achieve and circulate highparticle laden fluid under pressure may facilitate the successful use ofparticle jet drilling. Traditional oilfield drilling and/or servicingpumps are not designed to handle the abrasive nature of the particlesused for particle jet drilling for extended periods of time. Wear on thepump components may be high resulting in impractical maintenance andrepairs. One type of pump that may be used for particle jet drilling isa heavy duty piston membrane pump. Heavy duty piston membrane pumps maybe available from ABEL GmbH & Co. KG (Buchen, Germany). Piston membranepumps have been used for long term, continuous pumping of slurriescontaining high total solids in the mining and power industries. Pistonmembrane pumps are similar to triplex pumps used for drilling operationsin the oil and gas industry except heavy duty preformed membranesseparate the slurry from the hydraulic side of the pump. In thisfashion, the solids laden fluid is brought up to pressure in theinjection line in one step and circulated downhole without damaging theinternal mechanisms of the pump.

Another type of pump that may be used for particle jet drilling is anannular pressure exchange pump. Annular pressure exchange pumps may beavailable from Macmahon Mining Services Pty Ltd (Lonsdale, Australia).Annular pressure exchange pumps have been used for long term, continuouspumping of slurries containing high total solids in the mining industry.Annular pressure exchange pumps use hydraulic oil to compress a hoseinside a high-strength pressure chamber in a peristaltic like way todisplace the contents of the hose. Annular pressure exchange pumps mayobtain continuous flow by having twin chambers. One chamber fills whilethe other chamber is purged.

The BHA may include a downhole electric orienter. The downhole electricorienter may allow for directional drilling by directing one or morejets or particle jet drilling nozzles in an appropriate fashion tofacilitate forward hole making progress in the desired direction. Thedownhole electric orienter may be coupled to a computer control systemthrough one or more integral data lines of the composite coiled tubing.Power for the downhole electric orienter may be supplied through anintegral power line of the composite coiled tubing or through a batterysystem in the BHA.

Bubble entrained mud may be used as the drilling fluid. Bubble entrainedmud may allow for particle jet drilling without raising the equivalentcirculating density to unacceptable levels. A form of managed pressuredrilling may be affected by varying the density of bubble entrainment.In some embodiments, particles in the drilling fluid may be separatedfrom the drilling fluid using magnetic recovery when the particlesinclude iron or alloys that may be influenced by magnetic fields. Bubbleentrained mud may be used because using air or other gas as the drillingfluid may result in excessive wear of components from high velocityparticles in the return stream. The density of the bubble entrained mudgoing downhole as a function of real time gains and losses of fluid maybe automated using the computer control system.

In some embodiments, multiphase systems are used. For example, if gasinjection rates are low enough that wear rates are acceptable, agas-liquid circulating system may be used. Bottom hole circulatingpressures may be adjusted by the computer control system. The computercontrol system may adjust the gas and/or liquid injection rates.

In some embodiments, pipe-in-pipe drilling is used. Pipe-in-pipedrilling may include circulating fluid through the space between theouter pipe and the inner pipe instead of between the wellbore and thedrill string. Pipe-in-pipe drilling may be used if contact of thedrilling fluid with one or more fresh water aquifers is not acceptable.Pipe-in-pipe drilling may be used if the density of the drilling fluidcannot be adjusted low enough to effectively reduce potential lostcirculation issues.

Downhole inertial navigation may be part of the BHA. The use of downholeinertial navigation allows for determination of the position (includingdepth, azimuth and inclination) without magnetic sensors. Magneticinterference from casings and/or emissions from the high density ofwells in the formation may interfere with a system that determines theposition of the BHA based on magnet sensors.

The computer control system may receive information from the BHA. Thecomputer control system may process the information to determine theposition of the BHA. The computer control system may control drillingfluid rate, drilling fluid density, drilling fluid pressure, particledensity, other variables, and/or the downhole electric orienter tocontrol the rate of penetration and/or the direction of boreholeformation.

FIG. 39 depicts a representation of an embodiment of bottom holeassembly 420 used to form an opening in the formation. Composite coiledtubing 1768 may be secured to connector 1770 of BHA 420. Connector 1770may be coupled to combination circulation and disconnect sub 1772. Sub1772 may include ports 1774. Sub 1772 may be coupled to tractor system1776. Tractor system 1776 may include a plurality of grippers 1778 andram 1780. Tractor system 1776 may be coupled to sensor sub 1782 thatincludes inertial navigation sensors, pressure sensors, temperaturesensors and/or other sensors. Sensor sub 1782 may be coupled to orienter1784. Orienter 1784 may be coupled to jet head 1786. Jet head 1786 mayinclude centralizers 1788. Other BHA embodiments may include othercomponents and/or the same components in a different order.

In some embodiments, the jet head is rotated during use. The BHA mayinclude a motor for rotating the jet head. FIG. 40 depicts an embodimentof jet head 1786 with multiple nozzles 1790. The motor in the BHA mayrotate jet head 1786 in the direction indicated by the arrow. Nozzles1790 may direct particle jet streams 1792 against the formation. FIG. 41depicts an embodiment of jet head 1786 with single nozzles 1790. Nozzle1790 may direct particle jet stream 1792 against the formation.

In some embodiments, the jet head is not rotated during use. FIG. 42depicts an embodiment of non-rotational jet head 1786. Jet head 1786 mayinclude one or more nozzles 1790 that direct particle jet streamsagainst the formation.

Direction change of the wellbore formed by the BHA may be controlled ina number of ways. FIG. 43 depicts a representation wherein the BHAincludes an electrical orienter 1784. Electrical orienter 1784 adjustsangle θ between a back portion of the BHA and jet head 1786 that allowsthe BHA to form the opening in the direction indicated by arrow 1794.FIG. 44 depicts a representation wherein jet head 1786 includesdirectional jets 1796 around the circumference of the jet head.Directing fluid through one or more of the directional jets 1796 appliesa force in the direction indicated by arrow 1798 to jet head 1786 thatmoves the jet head so that one or more jets of the jet head form thewellbore in the direction indicated by arrow 1794.

In some embodiments, the tractor system of the BHA may be used to changethe direction of wellbore formation. FIG. 45 depicts tractor system 1776in use to change the direction of wellbore formation to the directionindicated by arrow 1794. One or more grippers of the rear gripperassembly may be extended to contact the formation and establish adesired angle of jet head. Ram 1780 may be extended to move jet headforward. When ram 1780 is fully extended, grippers of the front gripperassembly may be extended to contact the formation, and grippers of theread gripper assembly may be retracted to allow the ram to becompressed. Force may be applied to the coiled tubing to compress ram1780. When the ram is compressed, grippers of the front gripper assemblymay be retracted, and grippers of the rear gripper assembly may beextended to contact the formation and set the jet head in the desireddirection. Additional wellbore may be formed by directing particle jetsthrough the jet head while extending ram 1780.

In some embodiments, robots are used to perform a task in a wellboreformed or being formed using composite coiled tubing. The task may be,but is not limited to, providing traction to move the coiled tubing,surveying, removing cuttings, logging, and/or freeing pipe. For example,a robot may be used when drilling a horizontal opening if enough weightcannot be applied to the BHA to advance the coiled tubing and BHA in theformed borehole. The robot may be sent down the borehole. The robot mayclamp to the composite coiled tubing or BHA. Portions of the robot mayextend to engage the formation. Traction between the robot and theformation may be used to advance the robot forward so that the compositecoiled tubing and the BHA advance forward. The displacement data fromthe forward advancement of the BHA using the robot may be supplieddirectly to the inertial navigation system to improve accuracy of theopening being formed.

The robots may be battery powered. To use the robot, drilling could bestopped, and the robot could be connected to the outside of thecomposite coiled tubing. The robot would run along the outside of thecomposite coiled tubing to the bottom of the hole. If needed, the robotcould electrically couple to the BHA. The robot could couple to acontact plate on the BHA. The BHA may include a step-down transformerthat brings the high voltage, low current electricity supplied to theBHA to a lower voltage and higher current (for example, one third thevoltage and three times the amperage supplied to the BHA). The lowervoltage, higher current electricity supplied from the step-downtransformer may be used to recharge the batteries of the robot. In someembodiments, the robot may function while coupled to the BHA. Thebatteries may supply sufficient energy for the robot to travel to thedrill bit and back to the surface.

A robot may be run integral to the BHA on the end of the compositecoiled tubing. Portions of the robot may extend to engage the formation.Traction between the robot and the formation may be used to advance therobot forward so that the composite coiled tubing and the BHA advanceforward. The integral robot could be battery powered, could be poweredby the composite coiled tubing power lines or could be hydraulicallypowered by flow through the BHA.

FIG. 46 depicts a perspective representation of opened robot 1800. Robot1800 may be used for propelling the BHA forward in the wellbore. Robot1800 may include electronics, a battery, and a drive mechanism such aswheels, chains, treads, or other mechanism for advancing the robotforward. The battery and the electronics may be power the drivemechanism. Robot 1800 may be placed around composite coiled tubing andclosed. Robot 1800 may travel down the composite coiled tubing butcannot pass over the BHA. FIG. 47 depicts a representation of robotattached to composite coiled tubing 1768 and abutting BHA 420. Whenrobot 1800 reaches BHA 420, the robot may electrically couple to theBHA. BHA 420 may supply power to the robot to power the drive mechanismand/or recharge the battery of the robot. BHA 420 may send controlsignals to the electronics of robot 1800 that control the operation ofthe robot when the robot is coupled to the BHA. The control signalsprovided by BHA 420 may instruct robot 1800 to move forward to move theBHA forward.

Some wellbores formed in the formation may be used to facilitateformation of a perimeter barrier around a treatment area. Heat sourcesin the treatment area may heat hydrocarbons in the formation within thetreatment area. The perimeter barrier may be, but is not limited to, alow temperature or frozen barrier formed by freeze wells, a wax barrierformed in the formation, dewatering wells, a grout wall formed in theformation, a sulfur cement barrier, a barrier formed by a gel producedin the formation, a barrier formed by precipitation of salts in theformation, a barrier formed by a polymerization reaction in theformation, and/or sheets driven into the formation. Heat sources,production wells, injection wells, dewatering wells, and/or monitoringwells may be installed in the treatment area defined by the barrierprior to, simultaneously with, or after installation of the barrier.

A low temperature zone around at least a portion of a treatment area maybe formed by freeze wells. In an embodiment, refrigerant is circulatedthrough freeze wells to form low temperature zones around each freezewell. The freeze wells are placed in the formation so that the lowtemperature zones overlap and form a low temperature zone around thetreatment area. The low temperature zone established by freeze wells ismaintained below the freezing temperature of aqueous fluid in theformation. Aqueous fluid entering the low temperature zone freezes andforms the frozen barrier. In other embodiments, the freeze barrier isformed by batch operated freeze wells. A cold fluid, such as liquidnitrogen, is introduced into the freeze wells to form low temperaturezones around the freeze wells. The fluid is replenished as needed.

In some embodiments, two or more rows of freeze wells are located aboutall or a portion of the perimeter of the treatment area to form a thickinterconnected low temperature zone. Thick low temperature zones may beformed adjacent to areas in the formation where there is a high flowrate of aqueous fluid in the formation. The thick barrier may ensurethat breakthrough of the frozen barrier established by the freeze wellsdoes not occur.

In some embodiments, a double barrier system is used to isolate atreatment area. The double barrier system may be formed with a firstbarrier and a second barrier. The first barrier may be formed around atleast a portion of the treatment area to inhibit fluid from entering orexiting the treatment area. The second barrier may be formed around atleast a portion of the first barrier to isolate an inter-barrier zonebetween the first barrier and the second barrier. The inter-barrier zonemay have a thickness from about 1 m to about 300 m. In some embodiments,the thickness of the inter-barrier zone is from about 10 m to about 100m, or from about 20 m to about 50 m.

The double barrier system may allow greater project depths than a singlebarrier system. Greater depths are possible with the double barriersystem because the stepped differential pressures across the firstbarrier and the second barrier is less than the differential pressureacross a single barrier. The smaller differential pressures across thefirst barrier and the second barrier make a breach of the double barriersystem less likely to occur at depth for the double barrier system ascompared to the single barrier system. In some embodiments, additionalbarriers may be positioned to connect the inner barrier to the outerbarrier. The additional barriers may further strengthen the doublebarrier system and define compartments that limit the amount of fluidthat can pass from the inter-barrier zone to the treatment area should abreach occur in the first barrier.

The first barrier and the second barrier may be the same type of barrieror different types of barriers. In some embodiments, the first barrierand the second barrier are formed by freeze wells. In some embodiments,the first barrier is formed by freeze wells, and the second barrier is agrout wall. The grout wall may be formed of cement, sulfur, sulfurcement, or combinations thereof. In some embodiments, a portion of thefirst barrier and/or a portion of the second barrier is a naturalbarrier, such as an impermeable rock formation.

In some embodiments, one or both barriers may be formed from wellborespositioned in the formation. The position of the wellbores used to formthe second barrier may be adjusted relative to the wellbores used toform the first barrier to limit a separation distance between a breachor portion of the barrier that is difficult to form and the nearestwellbore. For example, if freeze wells are used to form both barriers ofa double barrier system, the position of the freeze wells may beadjusted to facilitate formation of the barriers and limit the distancebetween a potential breach and the closest wells to the breach.Adjusting the position of the wells of the second barrier relative tothe wells of the first barrier may also be used when one or more of thebarriers are barriers other than freeze barriers (for example,dewatering wells, cement barriers, grout barriers, and/or wax barriers).

In some embodiments, wellbores for forming the first barrier are formedin a row in the formation. During formation of the wellbores, loggingtechniques and/or analysis of cores may be used to determine theprincipal fracture direction and/or the direction of water flow in oneor more layers of the formation. In some embodiments, two or more layersof the formation may have different principal fracture directions and/orthe directions of water flow that need to be addressed. In suchformations, three or more barriers may need to be formed in theformation to allow for formation of the barriers that inhibit inflow offormation fluid into the treatment area or outflow of formation fluidfrom the treatment area. Barriers may be formed to isolate particularlayers in the formation.

The principal fracture direction and/or the direction of water flow maybe used to determine the placement of wells used to form the secondbarrier relative to the wells used to form the first barrier. Theplacement of the wells may facilitate formation of the first barrier andthe second barrier.

FIG. 48 depicts a schematic representation of barrier wells 200 used toform a first barrier and barrier wells 200′ used to form a secondbarrier when the principal fracture direction and/or the direction ofwater flow is at angle A relative to the first barrier. The principalfracture direction and/or direction of water flow is indicated by arrow1802. The case where angle A is 0 is the case where the principalfracture direction and/or the direction of water flow is substantiallynormal to the barriers. Spacing between two adjacent barrier wells 200of the first barrier or between barrier wells 200′ of the second barrierare indicated by distance S. The spacing s may be 2 m, 3 m, 10 m orgreater. Distance d indicates the separation distance between the firstbarrier and the second barrier. Distance d may be less than s, equal tos, or greater than s. Barrier wells 200′ of the second barrier may haveoffset distance od relative to barrier wells 200 of the first barrier.Offset distance od may be calculated by the equation:od=s/2−d*tan(A)  (EQN. 1)

Using the od according to EQN. 1 maintains a maximum separation distanceof s/4 between a barrier well and a regular fracture extending betweenthe barriers. Having a maximum separation distance of s/4 by adjustingthe offset distance based on the principal fracture direction and/or thedirection of water flow may enhance formation of the first barrierand/or second barrier. Having a maximum separation distance of s/4 byadjusting the offset distance of wells of the second barrier relative tothe wells of the first barrier based on the principal fracture directionand/or the direction of water flow may reduce the time needed to reformthe first barrier and/or the second barrier should a breach of the firstbarrier and/or the second barrier occur.

In some embodiments, od may be set at a value between the valuegenerated by EQN. 1 and the worst case value. The worst case value of odmay be if barrier wells 200 of the first freeze barrier and barrierwells 200′ of the second barrier are located along the principalfracture direction and/or direction of water flow (i.e., along arrow1802). In such a case, the maximum separation distance would be s/2.Having a maximum separation distance of s/2 may slow the time needed toform the first barrier and/or the second barrier, or may inhibitformation of the barriers.

In some embodiments, the barrier wells for the treatment area are freezewells. Vertically positioned freeze wells and/or horizontally positionedfreeze wells may be positioned around sides of the treatment area. Ifthe upper layer (the overburden) or the lower layer (the underburden) ofthe formation is likely to allow fluid flow into the treatment area orout of the treatment area, horizontally positioned freeze wells may beused to form an upper and/or a lower barrier for the treatment area. Insome embodiments, an upper barrier and/or a lower barrier may not benecessary if the upper layer and/or the lower layer are at leastsubstantially impermeable. If the upper freeze barrier is formed,portions of heat sources, production wells, injection wells, and/ordewatering wells that pass through the low temperature zone created bythe freeze wells forming the upper freeze barrier wells may be insulatedand/or heat traced so that the low temperature zone does not adverselyaffect the functioning of the heat sources, production wells, injectionwells and/or dewatering wells passing through the low temperature zone.

FIG. 49 depicts an embodiment of freeze well 466. Freeze well 466 mayinclude canister 468, inlet conduit 470, spacers 472, and wellcap 474.Spacers 472 may position inlet conduit 470 in canister 468 so that anannular space is formed between the canister and the conduit. Spacers472 may promote turbulent flow of refrigerant in the annular spacebetween inlet conduit 470 and canister 468, but the spacers may alsocause a significant fluid pressure drop. Turbulent fluid flow in theannular space may be promoted by roughening the inner surface ofcanister 468, by roughening the outer surface of inlet conduit 470,and/or by having a small cross-sectional area annular space that allowsfor high refrigerant velocity in the annular space. In some embodiments,spacers are not used. Wellhead 476 may suspend canister 468 in wellbore428.

Formation refrigerant may flow through cold side conduit 478 from arefrigeration unit to inlet conduit 470 of freeze well 466. Theformation refrigerant may flow through an annular space between inletconduit 470 and canister 468 to warm side conduit 480. Heat may transferfrom the formation to canister 468 and from the canister to theformation refrigerant in the annular space. Inlet conduit 470 may beinsulated to inhibit heat transfer to the formation refrigerant duringpassage of the formation refrigerant into freeze well 466. In anembodiment, inlet conduit 470 is a high density polyethylene tube. Atcold temperatures, some polymers may exhibit a large amount of thermalcontraction. For example, a 260 m initial length of polyethylene conduitsubjected to a temperature of about −25° C. may contract by 6 m or more.If a high density polyethylene conduit, or other polymer conduit, isused, the large thermal contraction of the material must be taken intoaccount in determining the final depth of the freeze well. For example,the freeze well may be drilled deeper than needed, and the conduit maybe allowed to shrink back during use. In some embodiments, inlet conduit470 is an insulated metal tube. In some embodiments, the insulation maybe a polymer coating, such as, but not limited to, polyvinylchloride,high density polyethylene, and/or polystyrene.

Freeze well 466 may be introduced into the formation using a coiledtubing rig. In an embodiment, canister 468 and inlet conduit 470 arewound on a single reel. The coiled tubing rig introduces the canisterand inlet conduit 470 into the formation. In an embodiment, canister 468is wound on a first reel and inlet conduit 470 is wound on a secondreel. The coiled tubing rig introduces canister 468 into the formation.Then, the coiled tubing rig is used to introduce inlet conduit 470 intothe canister. In other embodiments, freeze well is assembled in sectionsat the wellbore site and introduced into the formation.

An insulated section of freeze well 466 may be placed adjacent tooverburden 482. An uninsulated section of freeze well 466 may be placedadjacent to layer or layers 484 where a low temperature zone is to beformed. In some embodiments, uninsulated sections of the freeze wellsmay be positioned adjacent only to aquifers or other permeable portionsof the formation that would allow fluid to flow into or out of thetreatment area. Portions of the formation where uninsulated sections ofthe freeze wells are to be placed may be determined using analysis ofcores and/or logging techniques.

FIG. 50 depicts an embodiment of the lower portion of freeze well 466.Freeze well may include canister 468, and inlet conduit 470. Latch pin486 may be welded to canister 468. Latch pin 486 may include taperedupper end 488 and groove 490. Tapered upper end 488 may facilitateplacement of a latch of inlet conduit 470 on latch pin 486. A springring of the latch may be positioned in groove 490 to couple inletconduit 470 to canister 468.

Inlet conduit 470 may include plastic portion 492, transition piece 494,outer sleeve 496, and inner sleeve 498. Plastic portion 492 may be aplastic conduit that carries refrigerant into freeze well 466. In someembodiments, plastic portion 492 is high density polyethylene pipe.

Transition piece 494 may be a transition between plastic portion 492 andouter sleeve 496. A plastic end of transition piece 494 may be fusionwelded to the end of plastic portion 492. A metal portion of transitionpiece may be butt welded to outer sleeve 496. In some embodiments, themetal portion and outer sleeve 496 are formed of 304 stainless steel.Other material may be used in other embodiments. Transition pieces 494may be available from Central Plastics Company (Shawnee, Okla., U.S.A.).

In some embodiments, outer sleeve 496 may include stop 500. Stop 500 mayengage a stop of inner sleeve 498 to limit a bottom position of theouter sleeve relative to the inner sleeve. In some embodiments, outersleeve 496 may include opening 502. Opening 502 may align with acorresponding opening in inner sleeve 498. A shear pin may be positionedin the openings during insertion of inlet conduit 470 in canister 468 toinhibit movement of outer sleeve 496 relative to inner sleeve 498. Shearpin is strong enough to support the weight of inner sleeve 498, but weakenough to shear due to force applied to the shear pin when outer sleeve496 moves upwards in the wellbore due to thermal contraction or duringinstallation of the inlet conduit after inlet conduit is coupled tocanister 468.

Inner sleeve 498 may be positioned in outer sleeve 496. Inner sleeve hasa length sufficient to inhibit separation of the inner sleeve from outersleeve 496 when inlet conduit has fully contracted due to exposure ofthe inlet conduit to low temperature refrigerant. Inner sleeve 498 mayinclude a plurality of slip rings 504 held in place by positioners 506,a plurality of openings 508, stop 510, and latch 512. Slip rings 504 mayposition inner sleeve 498 relative to outer sleeve 496 and allow theouter sleeve to move relative to the inner sleeve. In some embodiments,slip rings 504 are TEFLON® rings, such as polytetrafluoroethylene rings.Slip rings 504 may be made of different material in other embodiments.Positioners 506 may be steel rings welded to inner sleeve. Positioners506 may be thinner than slip rings 504. Positioners 506 may inhibitmovement of slip rings 504 relative to inner sleeve 498.

Openings 508 may be formed in a portion of inner sleeve 498 near thebottom of the inner sleeve. Openings 508 may allow refrigerant to passfrom inlet conduit 470 to canister 468. A majority of refrigerantflowing through inlet conduit 470 may pass through openings 508 tocanister 468. Some refrigerant flowing through inlet conduit 470 maypass to canister 468 through the space between inner sleeve 498 andouter sleeve 496.

Stop 510 may be located above openings 508. Stop 510 interacts with stop500 of outer sleeve 496 to limit the downward movement of the outersleeve relative to inner sleeve 498.

Latch 512 may be welded to the bottom of inner sleeve 498. Latch 512 mayinclude flared opening 514 that engages tapered end 488 of latch pin486. Latch 512 may include spring ring 516 that snaps into groove 490 oflatch pin 486 to couple inlet conduit 470 to canister 468.

To install freeze well 466, a wellbore is formed in the formation andcanister 468 is placed in the wellbore. The bottom of canister 468 haslatch pin 486. Transition piece is fusion welded to an end of coiledplastic portion 492 of inlet conduit 470. Latch 512 is placed incanister 468 and inlet conduit is spooled into the canister. Spacers maybe coupled to plastic portion 492 at selected positions. Latch may belowered until flared opening 514 engages tapered end 488 of latch pin486 and spring ring 516 snaps into the groove of the latch pin. Afterspring ring 516 engages latch pin 486, inlet conduit 470 may be movedupwards to shear the pin joining outer sleeve 496 to inner sleeve 498.Inlet conduit 470 may be coupled to the refrigerant supply piping andcanister may be coupled to the refrigerant return piping.

If needed, inlet conduit 470 may be removed from canister 468. Inletconduit may be pulled upwards to separate outer sleeve 496 from innersleeve 498. Plastic portion 492, transition piece 494, and outer sleeve496 may be pulled out of canister 468. A removal instrument may belowered into canister 468. The removal instrument may secure to innersleeve 498. The removal instrument may be pulled upwards to pull springring 516 of latch 512 out of groove 490 of latch pin 486. The removaltool may be withdrawn out of canister 468 to remove inner sleeve 498from the canister.

Grout, wax, polymer or other material may be used in combination withfreeze wells to provide a barrier for the in situ heat treatmentprocess. The material may fill cavities (vugs) in the formation andreduces the permeability of the formation. The material may have higherthermal conductivity than gas and/or formation fluid that fills cavitiesin the formation. Placing material in the cavities may allow for fasterlow temperature zone formation. The material may form a perpetualbarrier in the formation that may strengthen the formation. The use ofmaterial to form the barrier in unconsolidated or substantiallyunconsolidated formation material may allow for larger well spacing thanis possible without the use of the material. The combination of thematerial and the low temperature zone formed by freeze wells mayconstitute a double barrier for environmental regulation purposes. Insome embodiments, the material is introduced into the formation as aliquid, and the liquid sets in the formation to form a solid. Thematerial may be, but is not limited to, fine cement, micro fine cement,sulfur, sulfur cement, viscous thermoplastics, and/or waxes. Thematerial may include surfactants, stabilizers or other chemicals thatmodify the properties of the material. For example, the presence ofsurfactant in the material may promote entry of the material into smallopenings in the formation.

Material may be introduced into the formation through freeze wellwellbores. The material may be allowed to set. The integrity of the wallformed by the material may be checked. The integrity of the materialwall may be checked by logging techniques and/or by hydrostatic testing.If the permeability of a section formed by the material is too high,additional material may be introduced into the formation through freezewell wellbores. After the permeability of the section is sufficientlyreduced, freeze wells may be installed in the freeze well wellbores.

Material may be injected into the formation at a pressure that is high,but below the fracture pressure of the formation. In some embodiments,injection of material is performed in 16 m increments in the freezewellbore. Larger or smaller increments may be used if desired. In someembodiments, material is only applied to certain portions of theformation. For example, material may be applied to the formation throughthe freeze wellbore only adjacent to aquifer zones and/or to relativelyhigh permeability zones (for example, zones with a permeability greaterthan about 0.1 darcy). Applying material to aquifers may inhibitmigration of water from one aquifer to a different aquifer. For materialplaced in the formation through freeze well wellbores, the material mayinhibit water migration between aquifers during formation of the lowtemperature zone. The material may also inhibit water migration betweenaquifers when an established low temperature zone is allowed to thaw.

In some embodiments, the material used to form a barrier may be finecement and micro fine cement. Cement may provide structural support inthe formation. Fine cement may be ASTM type 3 Portland cement. Finecement may be less expensive than micro fine cement. In an embodiment, afreeze wellbore is formed in the formation. Selected portions of thefreeze wellbore are grouted using fine cement. Then, micro fine cementis injected into the formation through the freeze wellbore. The finecement may reduce the permeability down to about 10 millidarcy. Themicro fine cement may further reduce the permeability to about 0.1millidarcy. After the grout is introduced into the formation, a freezewellbore canister may be inserted into the formation. The process may berepeated for each freeze well that will be used to form the barrier.

In some embodiments, fine cement is introduced into every other freezewellbore. Micro fine cement is introduced into the remaining wellbores.For example, grout may be used in a formation with freeze wellbores setat about 5 m spacing. A first wellbore is drilled and fine cement isintroduced into the formation through the wellbore. A freeze wellcanister is positioned in the first wellbore. A second wellbore isdrilled 10 m away from the first wellbore. Fine cement is introducedinto the formation through the second wellbore. A freeze well canisteris positioned in the second wellbore. A third wellbore is drilledbetween the first wellbore and the second wellbore. In some embodiments,grout from the first and/or second wellbores may be detected in thecuttings of the third wellbore. Micro fine cement is introduced into theformation through the third wellbore. A freeze wellbore canister ispositioned in the third wellbore. The same procedure is used to form theremaining freeze wells that will form the barrier around the treatmentarea.

In some embodiments, material including wax is used to form a barrier ina formation. Wax barriers may be formed in wet, dry, or oil wettedformations. Wax barriers may be formed above, at the bottom of, and/orbelow the water table. Material including liquid wax introduced into theformation may permeate into adjacent rock and fractures in theformation. The material may permeate into rock to fill microscopic aswell as macroscopic pores and vugs in the rock. The wax solidifies toform a barrier that inhibits fluid flow into or out of a treatment area.A wax barrier may provide a minimal amount of structural support in theformation. Molten wax may reduce the strength of poorly consolidatedsoil by reducing inter-grain friction so that the poorly consolidatedsoil sloughs or liquefies. Poorly consolidated layers may beconsolidated by use of cement or other binding agents beforeintroduction of molten wax.

In some embodiments, the formation where a wax barrier is to beestablished is dewatered before and/or during formation of the waxbarrier. In some embodiments, the portion of the formation where the waxbarrier is to form is dewatered or diluted to remove or reduce salinewater that could adversely affect the properties of the materialintroduced into the formation to form the wax barrier.

In some embodiments, water is introduced into the formation duringformation of the wax barrier. Water may be introduced into the formationwhen the barrier is to be formed below the water table or in a dryportion of the formation. The water may be used to heat the formation toa desired temperature before introducing the material that forms the waxbarrier. The water may be introduced at an elevated temperature and/orthe water may be heated in the formation from one or more heaters.

The wax of the barrier may be a branched paraffin to inhibit biologicaldegradation of the wax. The wax may include stabilizers, surfactants orother chemicals that modify the physical and/or chemical properties ofthe wax. The physical properties may be tailored to meet specific needs.The wax may melt at a relative low temperature (for example, the wax mayhave a typical melting point of about 52° C.). The temperature at whichthe wax congeals may be at least 5° C., 10° C., 20° C., or 30° C. abovethe ambient temperature of the formation prior to any heating of theformation. When molten, the wax may have a relatively low viscosity (forexample, 4 to 10 cp at about 99° C.). The flash point of the wax may berelatively high (for example, the flash point may be over 204° C.). Thewax may have a density less than the density of water and may have aheat capacity that is less than half the heat capacity of water. Thesolid wax may have a low thermal conductivity (for example, about 0.18W/m ° C.) So that the solid wax is a thermal insulator. Waxes suitablefor forming a barrier are available as WAXFIX™ from Carter TechnologiesCompany (Sugar Land, Tex., U.S.A.). WAXFIX™ is very resistant tomicrobial attack. WAXFIX™ may have a half life of greater than 5000years.

In some embodiments, a wax barrier or wax barriers may be used as thebarriers for the in situ heat treatment process. In some embodiments, awax barrier may be used in conjunction with freeze wells that form a lowtemperature barrier around the treatment area. In some embodiments, thewax barrier is formed and freeze wells are installed in the wellboresused for introducing wax into the formation. In some embodiments, thewax barrier is formed in wellbores offset from the freeze wellwellbores. The wax barrier may be on the outside or the inside of thefreeze wells. In some embodiments, a wax barrier may be formed on boththe inside and outside of the freeze wells. The wax barrier may inhibitwater flow in the formation that would inhibit the formation of the lowtemperature zone by the freeze wells. In some embodiments, a wax barrieris formed in the inter-barrier zone between two freeze barriers of adouble barrier system.

Material used to form the wax barrier may be introduced into theformation through wellbores. The wellbores may include verticalwellbores, slanted wellbores, and/or horizontal wellbores (for example,wellbores with sections that are horizontally or near horizontallyoriented). The use of vertical wellbores, slanted wellbores, and/orhorizontal wellbores for forming the wax barrier allows the formation ofa barrier that seals both horizontal and vertical fractures.

Wellbores may be formed in the formation around the treatment area at aclose spacing. In some embodiments, the spacing is from about 1.5 m toabout 4 m. Larger or smaller spacings may be used. Low temperatureheaters may be inserted in the wellbores. The heaters may operate attemperatures from about 260° C. to about 320° C. so that the temperatureat the formation face is below the pyrolysis temperature of hydrocarbonsin the formation. The heaters may be activated to heat the formationuntil the overlap between two adjacent heaters raises the temperature ofthe zone between the two heaters above the melting temperature of thewax. Heating the formation to obtain superposition of heat with atemperature above the melting temperature of the wax may take one month,two months, or longer. After heating, the heaters may be turned off. Insome embodiments, the heaters are downhole antennas that operate atabout 10 MHz to heat the formation.

After heating, the material used to form the wax barrier may beintroduced into the wellbores to form the barrier. The material may flowinto the formation and fill any fractures and porosity that has beenheated. The wax in the material congeals when the wax flows to coldregions beyond the heated circumference. This wax barrier formationmethod may form a more complete barrier than some other methods of waxbarrier formation, but the time for heating may be longer than for someof the other methods. Also, if a low temperature barrier is to be formedwith the freeze wells placed in the wellbores used for injection of thematerial used to form the barrier, the freeze wells will have to removethe heat supplied to the formation to allow for introduction of thematerial used to form the barrier. The low temperature barrier may takelonger to form.

In some embodiments, the wax barrier may be formed using a conduitplaced in the wellbore. FIG. 51 depicts an embodiment of a system forforming a wax barrier in a formation. Wellbore 428 may extend into oneor more layers 484 below overburden 482. Wellbore 428 may be an openwellbore below overburden 482. One or more of the layers 484 may includefracture systems 518. One or more of the layers may be vuggy so that thelayer or a portion of the layer has a high porosity. Conduit 520 may bepositioned in wellbore 428. In some embodiments, low temperature heater522 may be strapped or attached to conduit 520. In some embodiments,conduit 520 may be a heater element. Heater 522 may be operated so thatthe heater does not cause pyrolysis of hydrocarbons adjacent to theheater. At least a portion of wellbore 428 may be filled with fluid. Thefluid may be formation fluid or water. Heater 522 may be activated toheat the fluid. A portion of the heated fluid may move outwards fromheater 522 into the formation. The heated fluid may be injected into thefractures and permeable vuggy zones. The heated fluid may be injectedinto the fractures and permeable vuggy zones by introducing heatedbarrier material into wellbore 428 in the annular space between conduit520 and the wellbore. The introduced material flows to the areas heatedby the fluid and congeals when the fluid reaches cold regions not heatedby the fluid. The material fills fracture systems 518 and permeablevuggy pathways heated by the fluid, but the material may not permeatethrough a significant portion of the rock matrix as when the hotmaterial is introduced into a heated formation as described above. Thematerial flows into fracture systems 518 a sufficient distance to joinwith material injected from an adjacent well so that a barrier to fluidflow through the fracture systems forms when the wax congeals. A portionof material may congeal along the wall of a fracture or a vug withoutcompletely blocking the fracture or filling the vug. The congealedmaterial may act as an insulator and allow additional liquid wax to flowbeyond the congealed portion to penetrate deeply into the formation andform blockages to fluid flow when the material cools below the meltingtemperature of the wax in the material.

Material in the annular space of wellbore 428 between conduit 520 andthe formation may be removed through conduit by displacing the materialwith water or other fluid. Conduit 520 may be removed and a freeze wellmay be installed in the wellbore. This method may use less material thanthe method described above. The heating of the fluid may be accomplishedin less than a week or within a day. The small amount of heat input mayallow for quicker formation of a low temperature barrier if freeze wellsare to be positioned in the wellbores used to introduce material intothe formation.

In some embodiments, a heater may be suspended in the well without aconduit that allows for removal of excess material from the wellbore.The material may be introduced into the well. After materialintroduction, the heater may be removed from the well. In someembodiments, a conduit may be positioned in the wellbore, but a heatermay not be coupled to the conduit. Hot material may be circulatedthrough the conduit so that the wax enters fractures systems and/or vugsadjacent to the wellbore.

In some embodiments, material may be used during the formation of awellbore to improve inter-zonal isolation and protect a low-pressurezone from inflow from a high-pressure zone. During wellbore formationwhere a high pressure zone and a low pressure zone are penetrated by acommon wellbore, it is possible for fluid from the high pressure zone toflow into the low pressure zone and cause an underground blowout. Toavoid this, the wellbore may be formed through the first zone. Then, anintermediate casing may be set and cemented through the first zone.Setting casing may be time consuming and expensive. Instead of setting acasing, material may be introduced to form a wax barrier that seals thefirst zone. The material may also inhibit or prevent mixing of highsalinity brines from lower, high pressure zones with fresher brines inupper, lower pressure zones.

FIG. 52A depicts wellbore 428 drilled to a first depth in formation 524.After the surface casing for wellbore 428 is set and cemented in place,the wellbore is drilled to the first depth which passes through apermeable zone, such as an aquifer. The permeable zone may be fracturesystem 518′. In some embodiments, a heater is placed in wellbore 428 toheat the vertical interval of fracture system 518′. In some embodiments,hot fluid is circulated in wellbore 428 to heat the vertical interval offracture system 518′. After heating, molten material is pumped downwellbore 428. The molten material flows a selected distance intofracture system 518′ before the material cools sufficiently to solidifyand form a seal. The molten material is introduced into formation 524 ata pressure below the fracture pressure of the formation. In someembodiments, pressure is maintained on the wellhead until the materialhas solidified. In some embodiments, the material is allowed to cooluntil the material in wellbore 428 is almost to the congealingtemperature of the material. The material in wellbore 428 may then bedisplaced out of the wellbore. Wax in the material makes the portion offormation 524 near wellbore 428 into a substantially impermeable zone.Wellbore 428 may be drilled to depth through one or more permeable zonesthat are at higher pressures than the pressure in the first permeablezone, such as fracture system 518″. Congealed wax in fracture system518′ may inhibit blowout into the lower pressure zone. FIG. 52B depictswellbore 428 drilled to depth with congealed wax 526 in formation 524.

In some embodiments, a material including wax may be used to contain andinhibit migration in a subsurface formation that has liquid hydrocarboncontaminants (for example, compounds such as benzene, toluene,ethylbenzene and xylene) condensed in fractures in the formation. Thelocation of the contaminants may be surrounded with heated injectionwells. The material may be introduced into the wells to form an outerwax barrier. The material injected into the fractures from the injectionwells may mix with the contaminants. The contaminants may be solubilizedinto the material. When the material congeals, the contaminants may bepermanently contained in the solid wax phase of the material.

In some embodiments, a portion or all of the wax barrier may be removedafter completion of the in situ heat treatment process. Removing all ora portion of the wax barrier may allow fluid to flow into and out of thetreatment area of the in situ heat treatment process. Removing all or aportion of the wax barrier may return flow conditions in the formationto substantially the same conditions as existed before the in situ heattreatment process. To remove a portion or all of the wax barrier,heaters may be used to heat the formation adjacent to the wax barrier.In some embodiments, the heaters raise the temperature above thedecomposition temperature of the material forming the wax barrier. Insome embodiments, the heaters raise the temperature above the meltingtemperature of the material forming the wax barrier. Fluid (for examplewater) may be introduced into the formation to drive the molten materialto one or more production wells positioned in the formation. Theproduction wells may remove the material from the formation.

In some embodiments, a composition that includes a cross-linkablepolymer may be used with or in addition to a material that includes waxto form the barrier. Such composition may be provided to the formationas is described above for the material that includes wax. Thecomposition may be configured to react and solidify after a selectedtime in the formation, thereby allowing the composition to be providedas a liquid to the formation. The cross-linkable polymer may include,for example, acrylates, methacrylates, urethanes, and/or epoxies. Across-linking initiator may be included in the composition. Thecomposition may also include a cross-linking inhibitor. Thecross-linking inhibitor may be configured to degrade while in theformation, thereby allowing the composition to solidify.

In situ heat treatment processes and solution mining processes may heatthe treatment area, remove mass from the treatment area, and greatlyincrease the permeability of the treatment area. In certain embodiments,the treatment area after being treated may have a permeability of atleast 0.1 darcy. In some embodiments, the treatment area after beingtreated has a permeability of at least 1 darcy, of at least 10 darcy, orof at least 100 darcy. The increased permeability allows the fluid tospread in the formation into fractures, microfractures, and/or porespaces in the formation. Outside of the treatment area, the permeabilitymay remain at the initial permeability of the formation. The increasedpermeability allows fluid introduced to flow easily within theformation.

In certain embodiments, a barrier may be formed in the formation after asolution mining process and/or an in situ heat treatment process byintroducing a fluid into the formation. The barrier may inhibitformation fluid from entering the treatment area after the solutionmining and/or in situ heat treatment processes have ended. The barrierformed by introducing fluid into the formation may allow for isolationof the treatment area.

The fluid introduced into the formation to form a barrier may includewax, bitumen, heavy oil, sulfur, polymer, gel, saturated salinesolution, and/or one or more reactants that react to form a precipitate,solid or high viscosity fluid in the formation. In some embodiments,bitumen, heavy oil, reactants and/or sulfur used to form the barrier areobtained from treatment facilities associated with the in situ heattreatment process. For example, sulfur may be obtained from a Clausprocess used to treat produced gases to remove hydrogen sulfide andother sulfur compounds.

The fluid may be introduced into the formation as a liquid, vapor, ormixed phase fluid. The fluid may be introduced into a portion of theformation that is at an elevated temperature. In some embodiments, thefluid is introduced into the formation through wells located near aperimeter of the treatment area. The fluid may be directed away from thetreatment area. The elevated temperature of the formation maintains orallows the fluid to have a low viscosity so that the fluid moves awayfrom the wells. A portion of the fluid may spread outwards in theformation towards a cooler portion of the formation. The relatively highpermeability of the formation allows fluid introduced from one wellboreto spread and mix with fluid introduced from other wellbores. In thecooler portion of the formation, the viscosity of the fluid increases, aportion of the fluid precipitates, and/or the fluid solidifies orthickens so that the fluid forms the barrier to flow of formation fluidinto or out of the treatment area.

In some embodiments, a low temperature barrier formed by freeze wellssurrounds all or a portion of the treatment area. As the fluidintroduced into the formation approaches the low temperature barrier,the temperature of the formation becomes colder. The colder temperatureincreases the viscosity of the fluid, enhances precipitation, and/orsolidifies the fluid to form the barrier to the flow of formation fluidinto or out of the formation. The fluid may remain in the formation as ahighly viscous fluid or a solid after the low temperature barrier hasdissipated.

In certain embodiments, saturated saline solution is introduced into theformation. Components in the saturated saline solution may precipitateout of solution when the solution reaches a colder temperature. Thesolidified particles may form the barrier to the flow of formation fluidinto or out of the formation. The solidified components may besubstantially insoluble in formation fluid.

In certain embodiments, brine is introduced into the formation as areactant. A second reactant, such as carbon dioxide, may be introducedinto the formation to react with the brine. The reaction may generate amineral complex that grows in the formation. The mineral complex may besubstantially insoluble to formation fluid. In an embodiment, the brinesolution includes a sodium and aluminum solution. The second reactantintroduced in the formation is carbon dioxide. The carbon dioxide reactswith the brine solution to produce dawsonite. The minerals may solidifyand form the barrier to the flow of formation fluid into or out of theformation.

In some embodiments, the barrier may be formed around a treatment areausing sulfur. Advantageously, elemental sulfur is insoluble in water.Liquid and/or solid sulfur in the formation may form a barrier toformation fluid flow into or out of the treatment area.

A sulfur barrier may be established in the formation during or beforeinitiation of heating to heat the treatment area of the in situ heattreatment process. In some embodiments, sulfur may be introduced intowellbores in the formation that are located between the treatment areaand a first barrier (for example, a low temperature barrier establishedby freeze wells). The formation adjacent to the wellbores that thesulfur is introduced into may be dewatered. In some embodiments, theformation adjacent to the wellbores that the sulfur is introduced intois heated to facilitate removal of water and to prepare the wellboresand adjacent formation for the introduction of sulfur. The formationadjacent to the wellbores may be heated to a temperature below thepyrolysis temperature of hydrocarbons in the formation. The formationmay be heated so that the temperature of a portion of the formationbetween two adjacent heaters is influenced by both heaters. In someembodiments, the heat may increase the permeability of the formation sothat a first wellbore is in fluid communication with an adjacentwellbore.

After the formation adjacent to the wellbores is heated, molten sulfurat a temperature below the pyrolysis temperature of hydrocarbons in theformation is introduced into the formation. Over a certain temperaturerange, the viscosity of molten sulfur increases with increasingtemperature. The molten sulfur introduced into the formation may be nearthe melting temperature of sulfur (about 115° C.) So that the sulfur hasa relatively low viscosity (about 4-10 cp). Heaters in the wellbores maybe temperature limited heaters with Curie temperatures near the meltingtemperature of sulfur so that the temperature of the molten sulfur staysrelatively constant and below temperatures resulting in the formation ofviscous molten sulfur. In some embodiments, the region adjacent to thewellbores may be heated to a temperature above the melting point ofsulfur, but below the pyrolysis temperature of hydrocarbons in theformation. The heaters may be turned off and the temperature in thewellbores may be monitored (for example, using a fiber optic temperaturemonitoring system). When the temperature in the wellbore cools to atemperature near the melting temperature of sulfur, molten sulfur may beintroduced into the formation.

The sulfur introduced into the formation is allowed to flow and diffuseinto the formation from the wellbores. As the sulfur enters portions ofthe formation below the melting temperature, the sulfur solidifies andforms a barrier to fluid flow in the formation. Sulfur may be introduceduntil the formation is not able to accept additional sulfur. Heating maybe stopped, and the formation may be allowed to naturally cool so thatthe sulfur in the formation solidifies. After introduction of thesulfur, the integrity of the formed barrier may be tested using pulsetests and/or tracer tests.

A barrier may be formed around the treatment area after the in situ heattreatment process. The sulfur may form a substantially permanent barrierin the formation. In some embodiments, a low temperature barrier formedby freeze wells surrounds the treatment area. Sulfur may be introducedon one or both sides of the low temperature barrier to form a barrier inthe formation. The sulfur may be introduced into the formation as vaporor a liquid. As the sulfur approaches the low temperature barrier, thesulfur may condense and/or solidify in the formation to form thebarrier.

In some embodiments, the sulfur may be introduced in the heated portionof the portion. The sulfur may be introduced into the formation throughwells located near the perimeter of the treatment area. The temperatureof the formation may be hotter than the vaporization temperature ofsulfur (about 445° C.). The sulfur may be introduced as a liquid, vaporor mixed phase fluid. If a part of the introduced sulfur is in theliquid phase, the heat of the formation may vaporize the sulfur. Thesulfur may flow outwards from the introduction wells towards coolerportions of the formation. The sulfur may condense and/or solidify inthe formation to form the barrier.

In some embodiments, the Claus reaction may be used to form sulfur inthe formation after the in situ heat treatment process. The Clausreaction is a gas phase equilibrium reaction. The Claus reaction is:4H₂S+2SO₂

3S₂+4H₂O  (EQN. 2)

Hydrogen sulfide may be obtained by separating the hydrogen sulfide fromthe produced fluid of an ongoing in situ heat treatment process. Aportion of the hydrogen sulfide may be burned to form the needed sulfurdioxide. Hydrogen sulfide may be introduced into the formation through anumber of wells in the formation. Sulfur dioxide may be introduced intothe formation through other wells. The wells used for injecting sulfurdioxide or hydrogen sulfide may have been production wells, heaterwells, monitor wells or other type of well during the in situ heattreatment process. The wells used for injecting sulfur dioxide orhydrogen sulfide may be near the perimeter of the treatment area. Thenumber of wells may be enough so that the formation in the vicinity ofthe injection wells does not cool to a point where the sulfur dioxideand the hydrogen sulfide can form sulfur and condense, rather thanremain in the vapor phase. The wells used to introduce the sulfurdioxide into the formation may also be near the perimeter of thetreatment area. In some embodiments, the hydrogen sulfide and sulfurdioxide may be introduced into the formation through the same wells (forexample, through two conduits positioned in the same wellbore). Thehydrogen sulfide and the sulfur dioxide may react in the formation toform sulfur and water. The sulfur may flow outwards in the formation andcondense and/or solidify to form the barrier in the formation.

The sulfur barrier may form in the formation beyond the area wherehydrocarbons in formation fluid generated by the heat treatment processcondense in the formation. Regions near the perimeter of the treatedarea may be at lower temperatures than the treated area. Sulfur maycondense and/or solidify from the vapor phase in these lower temperatureregions. Additional hydrogen sulfide, and/or sulfur dioxide may diffuseto these lower temperature regions. Additional sulfur may form by theClaus reaction to maintain an equilibrium concentration of sulfur in thevapor phase. Eventually, a sulfur barrier may form around the treatedzone. The vapor phase in the treated region may remain as an equilibriummixture of sulfur, hydrogen sulfide, sulfur dioxide, water vapor andother vapor products present or evolving from the formation.

The conversion to sulfur is favored at lower temperatures, so theconversion of hydrogen sulfide and sulfur dioxide to sulfur may takeplace a distance away from the wells that introduce the reactants intothe formation. The Claus reaction may result in the formation of sulfurwhere the temperature of the formation is cooler (for example where thetemperature of the formation is at temperatures from about 180° C. toabout 240° C.).

A temperature monitoring system may be installed in wellbores of freezewells and/or in monitor wells adjacent to the freeze wells to monitorthe temperature profile of the freeze wells and/or the low temperaturezone established by the freeze wells. The monitoring system may be usedto monitor progress of low temperature zone formation. The monitoringsystem may be used to determine the location of high temperature areas,potential breakthrough locations, or breakthrough locations after thelow temperature zone has formed. Periodic monitoring of the temperatureprofile of the freeze wells and/or low temperature zone established bythe freeze wells may allow additional cooling to be provided topotential trouble areas before breakthrough occurs. Additional coolingmay be provided at or adjacent to breakthroughs and high temperatureareas to ensure the integrity of the low temperature zone around thetreatment area. Additional cooling may be provided by increasingrefrigerant flow through selected freeze wells, installing an additionalfreeze well or freeze wells, and/or by providing a cryogenic fluid, suchas liquid nitrogen, to the high temperature areas. Providing additionalcooling to potential problem areas before breakthrough occurs may bemore time efficient and cost efficient than sealing a breach, reheatinga portion of the treatment area that has been cooled by influx of fluid,and/or remediating an area outside of the breached frozen barrier.

In some embodiments, a traveling thermocouple may be used to monitor thetemperature profile of selected freeze wells or monitor wells. In someembodiments, the temperature monitoring system includes thermocouplesplaced at discrete locations in the wellbores of the freeze wells, inthe freeze wells, and/or in the monitoring wells. In some embodiments,the temperature monitoring system comprises a fiber optic temperaturemonitoring system.

Fiber optic temperature monitoring systems are available from Sensornet(London, United Kingdom), Sensa (Houston, Tex., U.S.A.), Luna Energy(Blacksburg, Va., U.S.A.), Lios Technology GMBH (Cologne, Germany),Oxford Electronics Ltd. (Hampshire, United Kingdom), and Sabeus SensorSystems (Calabasas, Calif., U.S.A.). The fiber optic temperaturemonitoring system includes a data system and one or more fiber opticcables. The data system includes one or more lasers for sending light tothe fiber optic cable; and one or more computers, software andperipherals for receiving, analyzing, and outputting data. The datasystem may be coupled to one or more fiber optic cables.

A single fiber optic cable may be several kilometers long. The fiberoptic cable may be installed in many freeze wells and/or monitor wells.In some embodiments, two fiber optic cables may be installed in eachfreeze well and/or monitor well. The two fiber optic cables may becoupled. Using two fiber optic cables per well allows for compensationdue to optical losses that occur in the wells and allows for betteraccuracy of measured temperature profiles.

The fiber optic temperature monitoring system may be used to detect thelocation of a breach or a potential breach in a frozen barrier. Thesearch for potential breaches may be performed at scheduled intervals,for example, every two or three months. To determine the location of thebreach or potential breach, flow of formation refrigerant to the freezewells of interest is stopped. In some embodiments, the flow of formationrefrigerant to all of the freeze wells is stopped. The rise in thetemperature profiles, as well as the rate of change of the temperatureprofiles, provided by the fiber optic temperature monitoring system foreach freeze well can be used to determine the location of any breachesor hot spots in the low temperature zone maintained by the freeze wells.The temperature profile monitored by the fiber optic temperaturemonitoring system for the two freeze wells closest to the hot spot orfluid flow will show the quickest and greatest rise in temperature. Atemperature change of a few degrees Centigrade in the temperatureprofiles of the freeze wells closest to a troubled area may besufficient to isolate the location of the trouble area. The shut downtime of flow of circulation fluid in the freeze wells of interest neededto detect breaches, potential breaches, and hot spots may be on theorder of a few hours or days, depending on the well spacing and theamount of fluid flow affecting the low temperature zone.

Fiber optic temperature monitoring systems may also be used to monitortemperatures in heated portions of the formation during in situ heattreatment processes. Temperature monitoring systems positioned inproduction wells, heater wells, injection wells, and/or monitor wellsmay be used to measure temperature profiles in treatment areas subjectedto in situ heat treatment processes. The fiber of a fiber optic cableused in the heated portion of the formation may be clad with areflective material to facilitate retention of a signal or signalstransmitted down the fiber. In some embodiments, the fiber is clad withgold, copper, nickel, aluminum and/or alloys thereof. The cladding maybe formed of a material that is able to withstand chemical andtemperature conditions in the heated portion of the formation. Forexample, gold cladding may allow an optical sensor to be used up totemperatures of 700° C. In some embodiments, the fiber is clad withaluminum. The fiber may be dipped in or run through a bath of liquidaluminum. The clad fiber may then be allowed to cool to secure thealuminum to the fiber. The gold or aluminum cladding may reduce hydrogendarkening of the optical fiber.

A potential source of heat loss from the heated formation is due toreflux in wells. Refluxing occurs when vapors condense in a well andflow into a portion of the well adjacent to the heated portion of theformation. Vapors may condense in the well adjacent to the overburden ofthe formation to form condensed fluid. Condensed fluid flowing into thewell adjacent to the heated formation absorbs heat from the formation.Heat absorbed by condensed fluids cools the formation and necessitatesadditional energy input into the formation to maintain the formation ata desired temperature. Some fluids that condense in the overburden andflow into the portion of the well adjacent to the heated formation mayreact to produce undesired compounds and/or coke. Inhibiting fluids fromrefluxing may significantly improve the thermal efficiency of the insitu heat treatment system and/or the quality of the product producedfrom the in situ heat treatment system.

For some well embodiments, the portion of the well adjacent to theoverburden section of the formation is cemented to the formation. Insome well embodiments, the well includes packing material placed nearthe transition from the heated section of the formation to theoverburden. The packing material inhibits formation fluid from passingfrom the heated section of the formation into the section of thewellbore adjacent to the overburden. Cables, conduits, devices, and/orinstruments may pass through the packing material, but the packingmaterial inhibits formation fluid from passing up the wellbore adjacentto the overburden section of the formation.

In some embodiments, one or more baffle systems may be placed in thewellbores to inhibit reflux. The baffle systems may be obstructions tofluid flow into the heated portion of the formation. In someembodiments, refluxing fluid may revaporize on the baffle system beforecoming into contact with the heated portion of the formation.

In some embodiments, a gas may be introduced into the formation throughwellbores to inhibit reflux in the wellbores. In some embodiments, gasmay be introduced into wellbores that include baffle systems to inhibitreflux of fluid in the wellbores. The gas may be carbon dioxide,methane, nitrogen or other desired gas. In some embodiments, theintroduction of gas may be used in conjunction with one or more bafflesystems in the wellbores. The introduced gas may enhance heat exchangeat the baffle systems to help maintain top portions of the bafflesystems colder than the lower portions of the baffle systems.

The flow of production fluid up the well to the surface is desired forsome types of wells, especially for production wells. Flow of productionfluid up the well is also desirable for some heater wells that are usedto control pressure in the formation. The overburden, or a conduit inthe well used to transport formation fluid from the heated portion ofthe formation to the surface, may be heated to inhibit condensation onor in the conduit. Providing heat in the overburden, however, may becostly and/or may lead to increased cracking or coking of formationfluid as the formation fluid is being produced from the formation.

To avoid the need to heat the overburden or to heat the conduit passingthrough the overburden, one or more diverters may be placed in thewellbore to inhibit fluid from refluxing into the wellbore adjacent tothe heated portion of the formation. In some embodiments, the diverterretains fluid above the heated portion of the formation. Fluids retainedin the diverter may be removed from the diverter using a pump, gaslifting, and/or other fluid removal technique. In certain embodiments,two or more diverters that retain fluid above the heated portion of theformation may be located in the production well. Two or more divertersprovide a simple way of separating initial fractions of condensed fluidproduced from the in situ heat treatment system. A pump may be placed ineach of the diverters to remove condensed fluid from the diverters.

In some embodiments, the diverter directs fluid to a sump below theheated portion of the formation. An inlet for a lift system may belocated in the sump. In some embodiments, the intake of the lift systemis located in casing in the sump. In some embodiments, the intake of thelift system is located in an open wellbore. The sump is below the heatedportion of the formation. The intake of the pump may be located 1 m, 5m, 10 m, 20 m or more below the deepest heater used to heat the heatedportion of the formation. The sump may be at a cooler temperature thanthe heated portion of the formation. The sump may be more than 10° C.,more than 50° C., more than 75° C., or more than 100° C. below thetemperature of the heated portion of the formation. A portion of thefluid entering the sump may be liquid. A portion of the fluid enteringthe sump may condense within the sump. The lift system moves the fluidin the sump to the surface.

Production well lift systems may be used to efficiently transportformation fluid from the bottom of the production wells to the surface.Production well lift systems may provide and maintain the maximumrequired well drawdown (minimum reservoir producing pressure) andproducing rates. The production well lift systems may operateefficiently over a wide range of high temperature/multiphase fluids(gas/vapor/steam/water/hydrocarbon liquids) and production ratesexpected during the life of a typical project. Production well liftsystems may include dual concentric rod pump lift systems, chamber liftsystems and other types of lift systems.

Temperature limited heaters may be in configurations and/or may includematerials that provide automatic temperature limiting properties for theheater at certain temperatures. In certain embodiments, ferromagneticmaterials are used in temperature limited heaters. Ferromagneticmaterial may self-limit temperature at or near the Curie temperature ofthe material and/or the phase transformation temperature range toprovide a reduced amount of heat when a time-varying current is appliedto the material. In certain embodiments, the ferromagnetic materialself-limits temperature of the temperature limited heater at a selectedtemperature that is approximately the Curie temperature and/or in thephase transformation temperature range. In certain embodiments, theselected temperature is within about 35° C., within about 25° C., withinabout 20° C., or within about 10° C. of the Curie temperature and/or thephase transformation temperature range. In certain embodiments,ferromagnetic materials are coupled with other materials (for example,highly conductive materials, high strength materials, corrosionresistant materials, or combinations thereof) to provide variouselectrical and/or mechanical properties. Some parts of the temperaturelimited heater may have a lower resistance (caused by differentgeometries and/or by using different ferromagnetic and/ornon-ferromagnetic materials) than other parts of the temperature limitedheater. Having parts of the temperature limited heater with variousmaterials and/or dimensions allows for tailoring the desired heat outputfrom each part of the heater.

Temperature limited heaters may be more reliable than other heaters.Temperature limited heaters may be less apt to break down or fail due tohot spots in the formation. In some embodiments, temperature limitedheaters allow for substantially uniform heating of the formation. Insome embodiments, temperature limited heaters are able to heat theformation more efficiently by operating at a higher average heat outputalong the entire length of the heater. The temperature limited heateroperates at the higher average heat output along the entire length ofthe heater because power to the heater does not have to be reduced tothe entire heater, as is the case with typical constant wattage heaters,if a temperature along any point of the heater exceeds, or is about toexceed, a maximum operating temperature of the heater. Heat output fromportions of a temperature limited heater approaching a Curie temperatureand/or the phase transformation temperature range of the heaterautomatically reduces without controlled adjustment of the time-varyingcurrent applied to the heater. The heat output automatically reduces dueto changes in electrical properties (for example, electrical resistance)of portions of the temperature limited heater. Thus, more power issupplied by the temperature limited heater during a greater portion of aheating process.

In certain embodiments, the system including temperature limited heatersinitially provides a first heat output and then provides a reduced(second heat output) heat output, near, at, or above the Curietemperature and/or the phase transformation temperature range of anelectrically resistive portion of the heater when the temperaturelimited heater is energized by a time-varying current. The first heatoutput is the heat output at temperatures below which the temperaturelimited heater begins to self-limit. In some embodiments, the first heatoutput is the heat output at a temperature about 50° C., about 75° C.,about 100° C., or about 125° C. below the Curie temperature and/or thephase transformation temperature range of the ferromagnetic material inthe temperature limited heater.

The temperature limited heater may be energized by time-varying current(alternating current or modulated direct current) supplied at thewellhead. The wellhead may include a power source and other components(for example, modulation components, transformers, and/or capacitors)used in supplying power to the temperature limited heater. Thetemperature limited heater may be one of many heaters used to heat aportion of the formation.

In certain embodiments, the temperature limited heater includes aconductor that operates as a skin effect or proximity effect heater whentime-varying current is applied to the conductor. The skin effect limitsthe depth of current penetration into the interior of the conductor. Forferromagnetic materials, the skin effect is dominated by the magneticpermeability of the conductor. The relative magnetic permeability offerromagnetic materials is typically between 10 and 1000 (for example,the relative magnetic permeability of ferromagnetic materials istypically at least 10 and may be at least 50, 100, 500, 1000 orgreater). As the temperature of the ferromagnetic material is raisedabove the Curie temperature, or the phase transformation temperaturerange, and/or as the applied electrical current is increased, themagnetic permeability of the ferromagnetic material decreasessubstantially and the skin depth expands rapidly (for example, the skindepth expands as the inverse square root of the magnetic permeability).The reduction in magnetic permeability results in a decrease in the ACor modulated DC resistance of the conductor near, at, or above the Curietemperature, the phase transformation temperature range, and/or as theapplied electrical current is increased. When the temperature limitedheater is powered by a substantially constant current source, portionsof the heater that approach, reach, or are above the Curie temperatureand/or the phase transformation temperature range may have reduced heatdissipation. Sections of the temperature limited heater that are not ator near the Curie temperature and/or the phase transformationtemperature range may be dominated by skin effect heating that allowsthe heater to have high heat dissipation due to a higher resistive load.

Curie temperature heaters have been used in soldering equipment, heatersfor medical applications, and heating elements for ovens (for example,pizza ovens). Some of these uses are disclosed in U.S. Pat. Nos.5,579,575 to Lamome et al.; 5,065,501 to Henschen et al.; and 5,512,732to Yagnik et al., all of which are incorporated by reference as if fullyset forth herein. U.S. Pat. No. 4,849,611 to Whitney et al., which isincorporated by reference as if fully set forth herein, describes aplurality of discrete, spaced-apart heating units including a reactivecomponent, a resistive heating component, and a temperature responsivecomponent.

An advantage of using the temperature limited heater to heathydrocarbons in the formation is that the conductor is chosen to have aCurie temperature and/or a phase transformation temperature range in adesired range of temperature operation. Operation within the desiredoperating temperature range allows substantial heat injection into theformation while maintaining the temperature of the temperature limitedheater, and other equipment, below design limit temperatures. Designlimit temperatures are temperatures at which properties such ascorrosion, creep, and/or deformation are adversely affected. Thetemperature limiting properties of the temperature limited heaterinhibit overheating or burnout of the heater adjacent to low thermalconductivity “hot spots” in the formation. In some embodiments, thetemperature limited heater is able to lower or control heat outputand/or withstand heat at temperatures above 25° C., 37° C., 100° C.,250° C., 500° C., 700° C., 800° C., 900° C., or higher up to 1131° C.,depending on the materials used in the heater.

The temperature limited heater allows for more heat injection into theformation than constant wattage heaters because the energy input intothe temperature limited heater does not have to be limited toaccommodate low thermal conductivity regions adjacent to the heater. Forexample, in Green River oil shale there is a difference of at least afactor of 3 in the thermal conductivity of the lowest richness oil shalelayers and the highest richness oil shale layers. When heating such aformation, substantially more heat is transferred to the formation withthe temperature limited heater than with the conventional heater that islimited by the temperature at low thermal conductivity layers. The heatoutput along the entire length of the conventional heater needs toaccommodate the low thermal conductivity layers so that the heater doesnot overheat at the low thermal conductivity layers and burn out. Theheat output adjacent to the low thermal conductivity layers that are athigh temperature will reduce for the temperature limited heater, but theremaining portions of the temperature limited heater that are not athigh temperature will still provide high heat output. Because heatersfor heating hydrocarbon formations typically have long lengths (forexample, at least 10 m, 100 m, 300 m, 500 m, 1 km or more up to about 10km), the majority of the length of the temperature limited heater may beoperating below the Curie temperature and/or the phase transformationtemperature range while only a few portions are at or near the Curietemperature and/or the phase transformation temperature range of thetemperature limited heater.

The use of temperature limited heaters allows for efficient transfer ofheat to the formation. Efficient transfer of heat allows for reductionin time needed to heat the formation to a desired temperature. Forexample, in Green River oil shale, pyrolysis typically requires 9.5years to 10 years of heating when using a 12 m heater well spacing withconventional constant wattage heaters. For the same heater spacing,temperature limited heaters may allow a larger average heat output whilemaintaining heater equipment temperatures below equipment design limittemperatures. Pyrolysis in the formation may occur at an earlier timewith the larger average heat output provided by temperature limitedheaters than the lower average heat output provided by constant wattageheaters. For example, in Green River oil shale, pyrolysis may occur in 5years using temperature limited heaters with a 12 m heater well spacing.Temperature limited heaters counteract hot spots due to inaccurate wellspacing or drilling where heater wells come too close together. Incertain embodiments, temperature limited heaters allow for increasedpower output over time for heater wells that have been spaced too farapart, or limit power output for heater wells that are spaced too closetogether. Temperature limited heaters also supply more power in regionsadjacent the overburden and underburden to compensate for temperaturelosses in these regions.

Temperature limited heaters may be advantageously used in many types offormations. For example, in tar sands formations or relatively permeableformations containing heavy hydrocarbons, temperature limited heatersmay be used to provide a controllable low temperature output forreducing the viscosity of fluids, mobilizing fluids, and/or enhancingthe radial flow of fluids at or near the wellbore or in the formation.Temperature limited heaters may be used to inhibit excess coke formationdue to overheating of the near wellbore region of the formation.

In some embodiments, the use of temperature limited heaters eliminatesor reduces the need for expensive temperature control circuitry. Forexample, the use of temperature limited heaters eliminates or reducesthe need to perform temperature logging and/or the need to use fixedthermocouples on the heaters to monitor potential overheating at hotspots.

In certain embodiments, phase transformation (for example, crystallinephase transformation or a change in the crystal structure) of materialsused in a temperature limited heater change the selected temperature atwhich the heater self-limits. Ferromagnetic material used in thetemperature limited heater may have a phase transformation (for example,a transformation from ferrite to austenite) that decreases the magneticpermeability of the ferromagnetic material. This reduction in magneticpermeability is similar to reduction in magnetic permeability due to themagnetic transition of the ferromagnetic material at the Curietemperature. The Curie temperature is the magnetic transitiontemperature of the ferrite phase of the ferromagnetic material. Thereduction in magnetic permeability results in a decrease in the AC ormodulated DC resistance of the temperature limited heater near, at, orabove the temperature of the phase transformation and/or the Curietemperature of the ferromagnetic material.

The phase transformation of the ferromagnetic material may occur over atemperature range. The temperature range of the phase transformationdepends on the ferromagnetic material and may vary, for example, over arange of about 5° C. to a range of about 200° C. Because the phasetransformation takes place over a temperature range, the reduction inthe magnetic permeability due to the phase transformation takes placeover the temperature range. The reduction in magnetic permeability mayalso occur hysteretically over the temperature range of the phasetransformation. In some embodiments, the phase transformation back tothe lower temperature phase of the ferromagnetic material is slower thanthe phase transformation to the higher temperature phase (for example,the transition from austenite back to ferrite is slower than thetransition from ferrite to austenite). The slower phase transformationback to the lower temperature phase may cause hysteretic operation ofthe heater at or near the phase transformation temperature range thatallows the heater to slowly increase to higher resistance after theresistance of the heater reduces due to high temperature.

In some embodiments, the phase transformation temperature range overlapswith the reduction in the magnetic permeability when the temperatureapproaches the Curie temperature of the ferromagnetic material. Theoverlap may produce a faster drop in electrical resistance versustemperature than if the reduction in magnetic permeability is solely dueto the temperature approaching the Curie temperature. The overlap mayalso produce hysteretic behavior of the temperature limited heater nearthe Curie temperature and/or in the phase transformation temperaturerange.

In certain embodiments, the hysteretic operation due to the phasetransformation is a smoother transition than the reduction in magneticpermeability due to magnetic transition at the Curie temperature. Thesmoother transition may be easier to control (for example, electricalcontrol using a process control device that interacts with the powersupply) than the sharper transition at the Curie temperature. In someembodiments, the Curie temperature is located inside the phasetransformation range for selected metallurgies used in temperaturelimited heaters. This phenomenon provides temperature limited heaterswith the smooth transition properties of the phase transformation inaddition to a sharp and definite transition due to the reduction inmagnetic properties at the Curie temperature. Such temperature limitedheaters may be easy to control (due to the phase transformation) whileproviding finite temperature limits (due to the sharp Curie temperaturetransition). Using the phase transformation temperature range instead ofand/or in addition to the Curie temperature in temperature limitedheaters increases the number and range of metallurgies that may be usedfor temperature limited heaters.

In certain embodiments, alloy additions are made to the ferromagneticmaterial to adjust the temperature range of the phase transformation.For example, adding carbon to the ferromagnetic material may increasethe phase transformation temperature range and lower the onsettemperature of the phase transformation. Adding titanium to theferromagnetic material may increase the onset temperature of the phasetransformation and decrease the phase transformation temperature range.Alloy compositions may be adjusted to provide desired Curie temperatureand phase transformation properties for the ferromagnetic material. Thealloy composition of the ferromagnetic material may be chosen based ondesired properties for the ferromagnetic material (such as, but notlimited to, magnetic permeability transition temperature or temperaturerange, resistance versus temperature profile, or power output). Additionof titanium may allow higher Curie temperatures to be obtained whenadding cobalt to 410 stainless steel by raising the ferrite to austenitephase transformation temperature range to a temperature range that isabove, or well above, the Curie temperature of the ferromagneticmaterial.

In some embodiments, temperature limited heaters are more economical tomanufacture or make than standard heaters. Typical ferromagneticmaterials include iron, carbon steel, or ferritic stainless steel. Suchmaterials are inexpensive as compared to nickel-based heating alloys(such as nichrome, Kanthal™ (Bulten-Kanthal AB, Sweden), and/or LOHM™(Driver-Harris Company, Harrison, N.J., U.S.A.)) typically used ininsulated conductor (mineral insulated cable) heaters. In one embodimentof the temperature limited heater, the temperature limited heater ismanufactured in continuous lengths as an insulated conductor heater tolower costs and improve reliability.

In some embodiments, the temperature limited heater is placed in theheater well using a coiled tubing rig. A heater that can be coiled on aspool may be manufactured by using metal such as ferritic stainlesssteel (for example, 409 stainless steel) that is welded using electricalresistance welding (ERW). U.S. Pat. No. 7,032,809 to Hopkins, which isincorporated by reference as if fully set forth herein, describesforming seam-welded pipe. To form a heater section, a metal strip from aroll is passed through a former where it is shaped into a tubular andthen longitudinally welded using ERW.

In some embodiments, a composite tubular may be formed from theseam-welded tubular. The seam-welded tubular is passed through a secondformer where a conductive strip (for example, a copper strip) isapplied, drawn down tightly on the tubular through a die, andlongitudinally welded using ERW. A sheath may be formed bylongitudinally welding a support material (for example, steel such as347H or 347HH) over the conductive strip material. The support materialmay be a strip rolled over the conductive strip material. An overburdensection of the heater may be formed in a similar manner.

In certain embodiments, the overburden section uses a non-ferromagneticmaterial such as 304 stainless steel or 316 stainless steel instead of aferromagnetic material. The heater section and overburden section may becoupled using standard techniques such as butt welding using an orbitalwelder. In some embodiments, the overburden section material (thenon-ferromagnetic material) may be pre-welded to the ferromagneticmaterial before rolling. The pre-welding may eliminate the need for aseparate coupling step (for example, butt welding). In an embodiment, aflexible cable (for example, a furnace cable such as a MGT 1000 furnacecable) may be pulled through the center after forming the tubularheater. An end bushing on the flexible cable may be welded to thetubular heater to provide an electrical current return path. The tubularheater, including the flexible cable, may be coiled onto a spool beforeinstallation into a heater well. In an embodiment, the temperaturelimited heater is installed using the coiled tubing rig. The coiledtubing rig may place the temperature limited heater in a deformationresistant container in the formation. The deformation resistantcontainer may be placed in the heater well using conventional methods.

Temperature limited heaters may be used for heating hydrocarbonformations including, but not limited to, oil shale formations, coalformations, tar sands formations, and formations with heavy viscousoils. Temperature limited heaters may also be used in the field ofenvironmental remediation to vaporize or destroy soil contaminants.Embodiments of temperature limited heaters may be used to heat fluids ina wellbore or sub-sea pipeline to inhibit deposition of paraffin orvarious hydrates. In some embodiments, a temperature limited heater isused for solution mining a subsurface formation (for example, an oilshale or a coal formation). In certain embodiments, a fluid (forexample, molten salt) is placed in a wellbore and heated with atemperature limited heater to inhibit deformation and/or collapse of thewellbore. In some embodiments, the temperature limited heater isattached to a sucker rod in the wellbore or is part of the sucker roditself. In some embodiments, temperature limited heaters are used toheat a near wellbore region to reduce near wellbore oil viscosity duringproduction of high viscosity crude oils and during transport of highviscosity oils to the surface. In some embodiments, a temperaturelimited heater enables gas lifting of a viscous oil by lowering theviscosity of the oil without coking the oil. Temperature limited heatersmay be used in sulfur transfer lines to maintain temperatures betweenabout 110° C. and about 130° C.

The ferromagnetic alloy or ferromagnetic alloys used in the temperaturelimited heater determine the Curie temperature of the heater. Curietemperature data for various metals is listed in “American Institute ofPhysics Handbook,” Second Edition, McGraw-Hill, pages 5-170 through5-176. Ferromagnetic conductors may include one or more of theferromagnetic elements (iron, cobalt, and nickel) and/or alloys of theseelements. In some embodiments, ferromagnetic conductors includeiron-chromium (Fe—Cr) alloys that contain tungsten (W) (for example,HCM12A and SAVE12 (Sumitomo Metals Co., Japan) and/or iron alloys thatcontain chromium (for example, Fe—Cr alloys, Fe—Cr—W alloys, Fe—Cr—V(vanadium) alloys, and Fe—Cr—Nb (Niobium) alloys). Of the three mainferromagnetic elements, iron has a Curie temperature of approximately770° C.; cobalt (Co) has a Curie temperature of approximately 1131° C.;and nickel has a Curie temperature of approximately 358° C. Aniron-cobalt alloy has a Curie temperature higher than the Curietemperature of iron. For example, iron-cobalt alloy with 2% by weightcobalt has a Curie temperature of approximately 800° C.; iron-cobaltalloy with 12% by weight cobalt has a Curie temperature of approximately900° C.; and iron-cobalt alloy with 20% by weight cobalt has a Curietemperature of approximately 950° C. Iron-nickel alloy has a Curietemperature lower than the Curie temperature of iron. For example,iron-nickel alloy with 20% by weight nickel has a Curie temperature ofapproximately 720° C., and iron-nickel alloy with 60% by weight nickelhas a Curie temperature of approximately 560° C.

Some non-ferromagnetic elements used as alloys raise the Curietemperature of iron. For example, an iron-vanadium alloy with 5.9% byweight vanadium has a Curie temperature of approximately 815° C. Othernon-ferromagnetic elements (for example, carbon, aluminum, copper,silicon, and/or chromium) may be alloyed with iron or otherferromagnetic materials to lower the Curie temperature.Non-ferromagnetic materials that raise the Curie temperature may becombined with non-ferromagnetic materials that lower the Curietemperature and alloyed with iron or other ferromagnetic materials toproduce a material with a desired Curie temperature and other desiredphysical and/or chemical properties. In some embodiments, the Curietemperature material is a ferrite such as NiFe₂O₄. In other embodiments,the Curie temperature material is a binary compound such as FeNi₃ orFe₃Al.

In some embodiments, the improved alloy includes carbon, cobalt, iron,manganese, silicon, or mixtures thereof. In certain embodiments, theimproved alloy includes, by weight: about 0.1% to about 10% cobalt;about 0.1% carbon, about 0.5% manganese, about 0.5% silicon, with thebalance being iron. In certain embodiments, the improved alloy includes,by weight: about 0.1% to about 10% cobalt; about 0.1% carbon, about 0.5%manganese, about 0.5% silicon, with the balance being iron.

In some embodiments, the improved alloy includes chromium, carbon,cobalt, iron, manganese, silicon, titanium, vanadium, or mixturesthereof. In certain embodiments, the improved alloy includes, by weight:about 5% to about 20% cobalt, about 0.1% carbon, about 0.5% manganese,about 0.5% silicon, about 0.1% to about 2% vanadium with the balancebeing iron. In some embodiments, the improved alloy includes, by weight:about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% toabout 0.5% manganese, above 0% to about 15% cobalt, above 0% to about 2%vanadium, above 0% to about 1% titanium, with the balance being iron. Insome embodiments, the improved alloy includes, by weight: about 12%chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about0.5% manganese, above 0% to about 2% vanadium, above 0% to about 1%titanium, with the balance being iron. In some embodiments, the improvedalloy includes, by weight: about 12% chromium, about 0.1% carbon, about0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 2%vanadium, with the balance being iron. In certain embodiments, theimproved alloy includes, by weight: about 12% chromium, about 0.1%carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0%to about 15% cobalt, above 0% to about 1% titanium, with the balancebeing iron. In certain embodiments, the improved alloy includes, byweight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about0.1% to about 0.5% manganese, above 0% to about 15% cobalt, with thebalance being iron. The addition of vanadium may allow for use of higheramounts of cobalt in the improved alloy.

Certain embodiments of temperature limited heaters may include more thanone ferromagnetic material. Such embodiments are within the scope ofembodiments described herein if any conditions described herein apply toat least one of the ferromagnetic materials in the temperature limitedheater.

Ferromagnetic properties generally decay as the Curie temperature and/orthe phase transformation temperature range is approached. The “Handbookof Electrical Heating for Industry” by C. James Erickson (IEEE Press,1995) shows a typical curve for 1% carbon steel (steel with 1% carbon byweight). The loss of magnetic permeability starts at temperatures above650° C. and tends to be complete when temperatures exceed 730° C. Thus,the self-limiting temperature may be somewhat below the actual Curietemperature and/or the phase transformation temperature range of theferromagnetic conductor. The skin depth for current flow in 1% carbonsteel is 0.132 cm at room temperature and increases to 0.445 cm at 720°C. From 720° C. to 730° C., the skin depth sharply increases to over 2.5cm. Thus, a temperature limited heater embodiment using 1% carbon steelbegins to self-limit between 650° C. and 730° C.

Skin depth generally defines an effective penetration depth oftime-varying current into the conductive material. In general, currentdensity decreases exponentially with distance from an outer surface tothe center along the radius of the conductor. The depth at which thecurrent density is approximately 1/e of the surface current density iscalled the skin depth. For a solid cylindrical rod with a diameter muchgreater than the penetration depth, or for hollow cylinders with a wallthickness exceeding the penetration depth, the skin depth, δ, is:δ=1981.5*(ρ/(μ*f))^(1/2);  (EQN. 3)in which:

-   -   δ=skin depth in inches;    -   ρ=resistivity at operating temperature (ohm-cm);    -   μ=relative magnetic permeability; and    -   f=frequency (Hz).        EQN. 3 is obtained from “Handbook of Electrical Heating for        Industry” by C. James Erickson (IEEE Press, 1995). For most        metals, resistivity (ρ) increases with temperature. The relative        magnetic permeability generally varies with temperature and with        current. Additional equations may be used to assess the variance        of magnetic permeability and/or skin depth on both temperature        and/or current. The dependence of μ on current arises from the        dependence of μ on the electromagnetic field.

Materials used in the temperature limited heater may be selected toprovide a desired turndown ratio. Turndown ratios of at least 1.1:1,2:1, 3:1, 4:1, 5:1, 10:1, 30:1, or 50:1 may be selected for temperaturelimited heaters. Larger turndown ratios may also be used. A selectedturndown ratio may depend on a number of factors including, but notlimited to, the type of formation in which the temperature limitedheater is located (for example, a higher turndown ratio may be used foran oil shale formation with large variations in thermal conductivitybetween rich and lean oil shale layers) and/or a temperature limit ofmaterials used in the wellbore (for example, temperature limits ofheater materials). In some embodiments, the turndown ratio is increasedby coupling additional copper or another good electrical conductor tothe ferromagnetic material (for example, adding copper to lower theresistance above the Curie temperature and/or the phase transformationtemperature range).

The temperature limited heater may provide a maximum heat output (poweroutput) below the Curie temperature and/or the phase transformationtemperature range of the heater. In certain embodiments, the maximumheat output is at least 400 W/m (Watts per meter), 600 W/m, 700 W/m, 800W/m, or higher up to 2000 W/m. The temperature limited heater reducesthe amount of heat output by a section of the heater when thetemperature of the section of the heater approaches or is above theCurie temperature and/or the phase transformation temperature range. Thereduced amount of heat may be substantially less than the heat outputbelow the Curie temperature and/or the phase transformation temperaturerange. In some embodiments, the reduced amount of heat is at most 400W/m, 200 W/m, 100 W/m or may approach 0 W/m.

In certain embodiments, the temperature limited heater operatessubstantially independently of the thermal load on the heater in acertain operating temperature range. “Thermal load” is the rate thatheat is transferred from a heating system to its surroundings. It is tobe understood that the thermal load may vary with temperature of thesurroundings and/or the thermal conductivity of the surroundings. In anembodiment, the temperature limited heater operates at or above theCurie temperature and/or the phase transformation temperature range ofthe temperature limited heater such that the operating temperature ofthe heater increases at most by 3° C., 2° C., 1.5° C., 1° C., or 0.5° C.for a decrease in thermal load of 1 W/m proximate to a portion of theheater. In certain embodiments, the temperature limited heater operatesin such a manner at a relatively constant current.

The AC or modulated DC resistance and/or the heat output of thetemperature limited heater may decrease as the temperature approachesthe Curie temperature and/or the phase transformation temperature rangeand decrease sharply near or above the Curie temperature due to theCurie effect and/or phase transformation effect. In certain embodiments,the value of the electrical resistance or heat output above or near theCurie temperature and/or the phase transformation temperature range isat most one-half of the value of electrical resistance or heat output ata certain point below the Curie temperature and/or the phasetransformation temperature range. In some embodiments, the heat outputabove or near the Curie temperature and/or the phase transformationtemperature range is at most 90%, 70%, 50%, 30%, 20%, 10%, or less (downto 1%) of the heat output at a certain point below the Curie temperatureand/or the phase transformation temperature range (for example, 30° C.below the Curie temperature, 40° C. below the Curie temperature, 50° C.below the Curie temperature, or 100° C. below the Curie temperature). Incertain embodiments, the electrical resistance above or near the Curietemperature and/or the phase transformation temperature range decreasesto 80%, 70%, 60%, 50%, or less (down to 1%) of the electrical resistanceat a certain point below the Curie temperature and/or the phasetransformation temperature range (for example, 30° C. below the Curietemperature, 40° C. below the Curie temperature, 50° C. below the Curietemperature, or 100° C. below the Curie temperature).

In some embodiments, AC frequency is adjusted to change the skin depthof the ferromagnetic material. For example, the skin depth of 1% carbonsteel at room temperature is 0.132 cm at 60 Hz, 0.0762 cm at 180 Hz, and0.046 cm at 440 Hz. Since heater diameter is typically larger than twicethe skin depth, using a higher frequency (and thus a heater with asmaller diameter) reduces heater costs. For a fixed geometry, the higherfrequency results in a higher turndown ratio. The turndown ratio at ahigher frequency is calculated by multiplying the turndown ratio at alower frequency by the square root of the higher frequency divided bythe lower frequency. In some embodiments, a frequency between 100 Hz and1000 Hz, between 140 Hz and 200 Hz, or between 400 Hz and 600 Hz is used(for example, 180 Hz, 540 Hz, or 720 Hz). In some embodiments, highfrequencies may be used. The frequencies may be greater than 1000 Hz.

To maintain a substantially constant skin depth until the Curietemperature and/or the phase transformation temperature range of thetemperature limited heater is reached, the heater may be operated at alower frequency when the heater is cold and operated at a higherfrequency when the heater is hot. Line frequency heating is generallyfavorable, however, because there is less need for expensive componentssuch as power supplies, transformers, or current modulators that alterfrequency. Line frequency is the frequency of a general supply ofcurrent. Line frequency is typically 60 Hz, but may be 50 Hz or anotherfrequency depending on the source for the supply of the current. Higherfrequencies may be produced using commercially available equipment suchas solid state variable frequency power supplies. Transformers thatconvert three-phase power to single-phase power with three times thefrequency are commercially available. For example, high voltagethree-phase power at 60 Hz may be transformed to single-phase power at180 Hz and at a lower voltage. Such transformers are less expensive andmore energy efficient than solid state variable frequency powersupplies. In certain embodiments, transformers that convert three-phasepower to single-phase power are used to increase the frequency of powersupplied to the temperature limited heater.

In certain embodiments, modulated DC (for example, chopped DC, waveformmodulated DC, or cycled DC) may be used for providing electrical powerto the temperature limited heater. A DC modulator or DC chopper may becoupled to a DC power supply to provide an output of modulated directcurrent. In some embodiments, the DC power supply may include means formodulating DC. One example of a DC modulator is a DC-to-DC convertersystem. DC-to-DC converter systems are generally known in the art. DC istypically modulated or chopped into a desired waveform. Waveforms for DCmodulation include, but are not limited to, square-wave, sinusoidal,deformed sinusoidal, deformed square-wave, triangular, and other regularor irregular waveforms.

The modulated DC waveform generally defines the frequency of themodulated DC. Thus, the modulated DC waveform may be selected to providea desired modulated DC frequency. The shape and/or the rate ofmodulation (such as the rate of chopping) of the modulated DC waveformmay be varied to vary the modulated DC frequency. DC may be modulated atfrequencies that are higher than generally available AC frequencies. Forexample, modulated DC may be provided at frequencies of at least 1000Hz. Increasing the frequency of supplied current to higher valuesadvantageously increases the turndown ratio of the temperature limitedheater.

In certain embodiments, the modulated DC waveform is adjusted or alteredto vary the modulated DC frequency. The DC modulator may be able toadjust or alter the modulated DC waveform at any time during use of thetemperature limited heater and at high currents or voltages. Thus,modulated DC provided to the temperature limited heater is not limitedto a single frequency or even a small set of frequency values. Waveformselection using the DC modulator typically allows for a wide range ofmodulated DC frequencies and for discrete control of the modulated DCfrequency. Thus, the modulated DC frequency is more easily set at adistinct value whereas AC frequency is generally limited to multiples ofthe line frequency. Discrete control of the modulated DC frequencyallows for more selective control over the turndown ratio of thetemperature limited heater. Being able to selectively control theturndown ratio of the temperature limited heater allows for a broaderrange of materials to be used in designing and constructing thetemperature limited heater.

In some embodiments, the modulated DC frequency or the AC frequency isadjusted to compensate for changes in properties (for example,subsurface conditions such as temperature or pressure) of thetemperature limited heater during use. The modulated DC frequency or theAC frequency provided to the temperature limited heater is varied basedon assessed downhole conditions. For example, as the temperature of thetemperature limited heater in the wellbore increases, it may beadvantageous to increase the frequency of the current provided to theheater, thus increasing the turndown ratio of the heater. In anembodiment, the downhole temperature of the temperature limited heaterin the wellbore is assessed.

In certain embodiments, the modulated DC frequency, or the AC frequency,is varied to adjust the turndown ratio of the temperature limitedheater. The turndown ratio may be adjusted to compensate for hot spotsoccurring along a length of the temperature limited heater. For example,the turndown ratio is increased because the temperature limited heateris getting too hot in certain locations. In some embodiments, themodulated DC frequency, or the AC frequency, are varied to adjust aturndown ratio without assessing a subsurface condition.

At or near the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic material, a relatively smallchange in voltage may cause a relatively large change in current to theload. The relatively small change in voltage may produce problems in thepower supplied to the temperature limited heater, especially at or nearthe Curie temperature and/or the phase transformation temperature range.The problems include, but are not limited to, reducing the power factor,tripping a circuit breaker, and/or blowing a fuse. In some cases,voltage changes may be caused by a change in the load of the temperaturelimited heater. In certain embodiments, an electrical current supply(for example, a supply of modulated DC or AC) provides a relativelyconstant amount of current that does not substantially vary with changesin load of the temperature limited heater. In an embodiment, theelectrical current supply provides an amount of electrical current thatremains within 15%, within 10%, within 5%, or within 2% of a selectedconstant current value when a load of the temperature limited heaterchanges.

Temperature limited heaters may generate an inductive load. Theinductive load is due to some applied electrical current being used bythe ferromagnetic material to generate a magnetic field in addition togenerating a resistive heat output. As downhole temperature changes inthe temperature limited heater, the inductive load of the heater changesdue to changes in the ferromagnetic properties of ferromagneticmaterials in the heater with temperature. The inductive load of thetemperature limited heater may cause a phase shift between the currentand the voltage applied to the heater.

A reduction in actual power applied to the temperature limited heatermay be caused by a time lag in the current waveform (for example, thecurrent has a phase shift relative to the voltage due to an inductiveload) and/or by distortions in the current waveform (for example,distortions in the current waveform caused by introduced harmonics dueto a non-linear load). Thus, it may take more current to apply aselected amount of power due to phase shifting or waveform distortion.The ratio of actual power applied and the apparent power that would havebeen transmitted if the same current were in phase and undistorted isthe power factor. The power factor is always less than or equal to 1.The power factor is 1 when there is no phase shift or distortion in thewaveform.

Actual power applied to a heater due to a phase shift may be describedby EQN. 4:P=I×V×cos(θ);  (EQN. 4)in which P is the actual power applied to a heater; I is the appliedcurrent; V is the applied voltage; and θ is the phase angle differencebetween voltage and current. Other phenomena such as waveform distortionmay contribute to further lowering of the power factor. If there is nodistortion in the waveform, then cos(θ) is equal to the power factor.

In certain embodiments, the temperature limited heater includes an innerconductor inside an outer conductor. The inner conductor and the outerconductor are radially disposed about a central axis. The inner andouter conductors may be separated by an insulation layer. In certainembodiments, the inner and outer conductors are coupled at the bottom ofthe temperature limited heater. Electrical current may flow into thetemperature limited heater through the inner conductor and returnthrough the outer conductor. One or both conductors may includeferromagnetic material.

The insulation layer may comprise an electrically insulating ceramicwith high thermal conductivity, such as magnesium oxide, aluminum oxide,silicon dioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. The insulating layer may be a compacted powder(for example, compacted ceramic powder). Compaction may improve thermalconductivity and provide better insulation resistance. For lowertemperature applications, polymer insulation made from, for example,fluoropolymers, polyimides, polyamides, and/or polyethylenes, may beused. In some embodiments, the polymer insulation is made ofperfluoroalkoxy (PFA) or polyetheretherketone (PEEK™ (Victrex Ltd,England)). The insulating layer may be chosen to be substantiallyinfrared transparent to aid heat transfer from the inner conductor tothe outer conductor. In an embodiment, the insulating layer istransparent quartz sand. The insulation layer may be air or anon-reactive gas such as helium, nitrogen, or sulfur hexafluoride. Ifthe insulation layer is air or a non-reactive gas, there may beinsulating spacers designed to inhibit electrical contact between theinner conductor and the outer conductor. The insulating spacers may bemade of, for example, high purity aluminum oxide or another thermallyconducting, electrically insulating material such as silicon nitride.The insulating spacers may be a fibrous ceramic material such as Nextel™312 (3M Corporation, St. Paul, Minn., U.S.A.), mica tape, or glassfiber. Ceramic material may be made of alumina, alumina-silicate,alumina-borosilicate, silicon nitride, boron nitride, or othermaterials.

The insulation layer may be flexible and/or substantially deformationtolerant. For example, if the insulation layer is a solid or compactedmaterial that substantially fills the space between the inner and outerconductors, the temperature limited heater may be flexible and/orsubstantially deformation tolerant. Forces on the outer conductor can betransmitted through the insulation layer to the solid inner conductor,which may resist crushing. Such a temperature limited heater may bebent, dog-legged, and spiraled without causing the outer conductor andthe inner conductor to electrically short to each other. Deformationtolerance may be important if the wellbore is likely to undergosubstantial deformation during heating of the formation.

In certain embodiments, an outermost layer of the temperature limitedheater (for example, the outer conductor) is chosen for corrosionresistance, yield strength, and/or creep resistance. In one embodiment,austenitic (non-ferromagnetic) stainless steels such as 201, 304H, 347H,347HH, 316H, 310H, 347HP, NF709 (Nippon Steel Corp., Japan) stainlesssteels, or combinations thereof may be used in the outer conductor. Theoutermost layer may also include a clad conductor. For example, acorrosion resistant alloy such as 800H or 347H stainless steel may beclad for corrosion protection over a ferromagnetic carbon steel tubular.If high temperature strength is not required, the outermost layer may beconstructed from ferromagnetic metal with good corrosion resistance suchas one of the ferritic stainless steels. In one embodiment, a ferriticalloy of 82.3% by weight iron with 17.7% by weight chromium (Curietemperature of 678° C.) provides desired corrosion resistance.

The Metals Handbook, vol. 8, page 291 (American Society of Materials(ASM)) includes a graph of Curie temperature of iron-chromium alloysversus the amount of chromium in the alloys. In some temperature limitedheater embodiments, a separate support rod or tubular (made from 347Hstainless steel) is coupled to the temperature limited heater made froman iron-chromium alloy to provide yield strength and/or creepresistance. In certain embodiments, the support material and/or theferromagnetic material is selected to provide a 100,000 hourcreep-rupture strength of at least 20.7 MPa at 650° C. In someembodiments, the 100,000 hour creep-rupture strength is at least 13.8MPa at 650° C. or at least 6.9 MPa at 650° C. For example, 347H steelhas a favorable creep-rupture strength at or above 650° C. In someembodiments, the 100,000 hour creep-rupture strength ranges from 6.9 MPato 41.3 MPa or more for longer heaters and/or higher earth or fluidstresses.

In temperature limited heater embodiments with both an innerferromagnetic conductor and an outer ferromagnetic conductor, the skineffect current path occurs on the outside of the inner conductor and onthe inside of the outer conductor. Thus, the outside of the outerconductor may be clad with the corrosion resistant alloy, such asstainless steel, without affecting the skin effect current path on theinside of the outer conductor.

A ferromagnetic conductor with a thickness of at least the skin depth atthe Curie temperature and/or the phase transformation temperature rangeallows a substantial decrease in resistance of the ferromagneticmaterial as the skin depth increases sharply near the Curie temperatureand/or the phase transformation temperature range. In certainembodiments when the ferromagnetic conductor is not clad with a highlyconducting material such as copper, the thickness of the conductor maybe 1.5 times the skin depth near the Curie temperature and/or the phasetransformation temperature range, 3 times the skin depth near the Curietemperature and/or the phase transformation temperature range, or even10 or more times the skin depth near the Curie temperature and/or thephase transformation temperature range. If the ferromagnetic conductoris clad with copper, thickness of the ferromagnetic conductor may besubstantially the same as the skin depth near the Curie temperatureand/or the phase transformation temperature range. In some embodiments,the ferromagnetic conductor clad with copper has a thickness of at leastthree-fourths of the skin depth near the Curie temperature and/or thephase transformation temperature range.

In certain embodiments, the temperature limited heater includes acomposite conductor with a ferromagnetic tubular and anon-ferromagnetic, high electrical conductivity core. Thenon-ferromagnetic, high electrical conductivity core reduces a requireddiameter of the conductor. For example, the conductor may be composite1.19 cm diameter conductor with a core of 0.575 cm diameter copper cladwith a 0.298 cm thickness of ferritic stainless steel or carbon steelsurrounding the core. The core or non-ferromagnetic conductor may becopper or copper alloy. The core or non-ferromagnetic conductor may alsobe made of other metals that exhibit low electrical resistivity andrelative magnetic permeabilities near 1 (for example, substantiallynon-ferromagnetic materials such as aluminum and aluminum alloys,phosphor bronze, beryllium copper, and/or brass). A composite conductorallows the electrical resistance of the temperature limited heater todecrease more steeply near the Curie temperature and/or the phasetransformation temperature range. As the skin depth increases near theCurie temperature and/or the phase transformation temperature range toinclude the copper core, the electrical resistance decreases verysharply.

The composite conductor may increase the conductivity of the temperaturelimited heater and/or allow the heater to operate at lower voltages. Inan embodiment, the composite conductor exhibits a relatively flatresistance versus temperature profile at temperatures below a regionnear the Curie temperature and/or the phase transformation temperaturerange of the ferromagnetic conductor of the composite conductor. In someembodiments, the temperature limited heater exhibits a relatively flatresistance versus temperature profile between 100° C. and 750° C. orbetween 300° C. and 600° C. The relatively flat resistance versustemperature profile may also be exhibited in other temperature ranges byadjusting, for example, materials and/or the configuration of materialsin the temperature limited heater. In certain embodiments, the relativethickness of each material in the composite conductor is selected toproduce a desired resistivity versus temperature profile for thetemperature limited heater.

In certain embodiments, the relative thickness of each material in acomposite conductor is selected to produce a desired resistivity versustemperature profile for a temperature limited heater. In an embodiment,the composite conductor is an inner conductor surrounded by 0.127 cmthick magnesium oxide powder as an insulator. The outer conductor may be304H stainless steel with a wall thickness of 0.127 cm. The outsidediameter of the heater may be about 1.65 cm.

A composite conductor (for example, a composite inner conductor or acomposite outer conductor) may be manufactured by methods including, butnot limited to, coextrusion, roll forming, tight fit tubing (forexample, cooling the inner member and heating the outer member, theninserting the inner member in the outer member, followed by a drawingoperation and/or allowing the system to cool), explosive orelectromagnetic cladding, arc overlay welding, longitudinal stripwelding, plasma powder welding, billet coextrusion, electroplating,drawing, sputtering, plasma deposition, coextrusion casting, magneticforming, molten cylinder casting (of inner core material inside theouter or vice versa), insertion followed by welding or high temperaturebraising, shielded active gas welding (SAG), and/or insertion of aninner pipe in an outer pipe followed by mechanical expansion of theinner pipe by hydroforming or use of a pig to expand and swage the innerpipe against the outer pipe. In some embodiments, a ferromagneticconductor is braided over a non-ferromagnetic conductor. In certainembodiments, composite conductors are formed using methods similar tothose used for cladding (for example, cladding copper to steel). Ametallurgical bond between copper cladding and base ferromagneticmaterial may be advantageous. Composite conductors produced by acoextrusion process that forms a good metallurgical bond (for example, agood bond between copper and 446 stainless steel) may be provided byAnomet Products, Inc. (Shrewsbury, Mass., U.S.A.).

In certain embodiments, it may be desirable to form a compositeconductor by various methods including longitudinal strip welding. Insome embodiments, however, it may be difficult to use longitudinal stripwelding techniques if the desired thickness of a layer of a firstmaterial has such a large thickness, in relation to the inner core/layeronto which such layer is to be bended, that it does not effectivelyand/or efficiently bend around an inner core or layer that is made of asecond material. In such circumstances, it may be beneficial to usemultiple thinner layers of the first material in the longitudinal stripwelding process such that the multiple thinner layers can more readilybe employed in a longitudinal strip welding process and coupled togetherto form a composite of the first material with the desired thickness.So, for example, a first layer of the first material may be bent aroundan inner core or layer of second material, and then a second layer ofthe first material may be bent around the first layer of the firstmaterial, with the thicknesses of the first and second layers being suchthat the first and second layers will readily bend around the inner coreor layer in a longitudinal strip welding process. Thus, the two layersof the first material may together form the total desired thickness ofthe first material.

FIGS. 53-74 depict various embodiments of temperature limited heaters.One or more features of an embodiment of the temperature limited heaterdepicted in any of these figures may be combined with one or morefeatures of other embodiments of temperature limited heaters depicted inthese figures. In certain embodiments described herein, temperaturelimited heaters are dimensioned to operate at a frequency of 60 Hz AC.It is to be understood that dimensions of the temperature limited heatermay be adjusted from those described herein to operate in a similarmanner at other AC frequencies or with modulated DC current.

The temperature limited heaters may be used in conductor-in-conduitheaters. In some embodiments of conductor-in-conduit heaters, themajority of the resistive heat is generated in the conductor, and theheat radiatively, conductively and/or convectively transfers to theconduit. In some embodiments of conductor-in-conduit heaters, themajority of the resistive heat is generated in the conduit.

FIG. 53 depicts a cross-sectional representation of an embodiment of thetemperature limited heater with an outer conductor having aferromagnetic section and a non-ferromagnetic section. FIGS. 54 and 55depict transverse cross-sectional views of the embodiment shown in FIG.53. In one embodiment, ferromagnetic section 528 is used to provide heatto hydrocarbon layers in the formation. Non-ferromagnetic section 530 isused in the overburden of the formation. Non-ferromagnetic section 530provides little or no heat to the overburden, thus inhibiting heatlosses in the overburden and improving heater efficiency. Ferromagneticsection 528 includes a ferromagnetic material such as 409 stainlesssteel or 410 stainless steel. Ferromagnetic section 528 has a thicknessof 0.3 cm. Non-ferromagnetic section 530 is copper with a thickness of0.3 cm. Inner conductor 532 is copper. Inner conductor 532 has adiameter of 0.9 cm. Electrical insulator 534 is silicon nitride, boronnitride, magnesium oxide powder, or another suitable insulator material.Electrical insulator 534 has a thickness of 0.1 cm to 0.3 cm.

FIG. 56 depicts a cross-sectional representation of an embodiment of atemperature limited heater with an outer conductor having aferromagnetic section and a non-ferromagnetic section placed inside asheath. FIGS. 57, 58, and 59 depict transverse cross-sectional views ofthe embodiment shown in FIG. 56. Ferromagnetic section 528 is 410stainless steel with a thickness of 0.6 cm. Non-ferromagnetic section530 is copper with a thickness of 0.6 cm. Inner conductor 532 is copperwith a diameter of 0.9 cm. Outer conductor 536 includes ferromagneticmaterial. Outer conductor 536 provides some heat in the overburdensection of the heater. Providing some heat in the overburden inhibitscondensation or refluxing of fluids in the overburden. Outer conductor536 is 409, 410, or 446 stainless steel with an outer diameter of 3.0 cmand a thickness of 0.6 cm. Electrical insulator 534 includes compactedmagnesium oxide powder with a thickness of 0.3 cm. In some embodiments,electrical insulator 534 includes silicon nitride, boron nitride, orhexagonal type boron nitride. Conductive section 538 may couple innerconductor 532 with ferromagnetic section 528 and/or outer conductor 536.

FIG. 60A and FIG. 60B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic innerconductor. Inner conductor 532 is a 1″ Schedule XXS 446 stainless steelpipe. In some embodiments, inner conductor 532 includes 409 stainlesssteel, 410 stainless steel, Invar 36, alloy 42-6, alloy 52, or otherferromagnetic materials. Inner conductor 532 has a diameter of 2.5 cm.Electrical insulator 534 includes compacted silicon nitride, boronnitride, or magnesium oxide powders; or polymers, Nextel ceramic fiber,mica, or glass fibers. Outer conductor 536 is copper or any othernon-ferromagnetic material, such as but not limited to copper alloys,aluminum and/or aluminum alloys. Outer conductor 536 is coupled tojacket 540. Jacket 540 is 304H, 316H, or 347H stainless steel. In thisembodiment, a majority of the heat is produced in inner conductor 532.

FIG. 61A and FIG. 61B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic innerconductor and a non-ferromagnetic core. Inner conductor 532 may be madeof 446 stainless steel, 409 stainless steel, 410 stainless steel, carbonsteel, Armco ingot iron, iron-cobalt alloys, or other ferromagneticmaterials. Core 542 may be tightly bonded inside inner conductor 532.Core 542 is copper or other non-ferromagnetic material. In certainembodiments, core 542 is inserted as a tight fit inside inner conductor532 before a drawing operation. In some embodiments, core 542 and innerconductor 532 are coextrusion bonded. Outer conductor 536 is 347Hstainless steel. A drawing or rolling operation to compact electricalinsulator 534 (for example, compacted silicon nitride, boron nitride, ormagnesium oxide powder) may ensure good electrical contact between innerconductor 532 and core 542. In this embodiment, heat is producedprimarily in inner conductor 532 until the Curie temperature and/or thephase transformation temperature range is approached. Resistance thendecreases sharply as current penetrates core 542.

FIG. 62A and FIG. 62B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor. Inner conductor 532 is nickel-clad copper. Electricalinsulator 534 is silicon nitride, boron nitride, or magnesium oxide.Outer conductor 536 is a 1″ Schedule XXS carbon steel pipe. In thisembodiment, heat is produced primarily in outer conductor 536, resultingin a small temperature differential across electrical insulator 534.

FIG. 63A and FIG. 63B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor that is clad with a corrosion resistant alloy. Inner conductor532 is copper. Outer conductor 536 is a 1″ Schedule XXS carbon steelpipe. Outer conductor 536 is coupled to jacket 540. Jacket 540 is madeof corrosion resistant material (for example, 347H stainless steel).Jacket 540 provides protection from corrosive fluids in the wellbore(for example, sulfidizing and carburizing gases). Heat is producedprimarily in outer conductor 536, resulting in a small temperaturedifferential across electrical insulator 534.

FIG. 64A and FIG. 64B depict cross-sectional representations of anembodiment of a temperature limited heater with a ferromagnetic outerconductor. The outer conductor is clad with a conductive layer and acorrosion resistant alloy. Inner conductor 532 is copper. Electricalinsulator 534 is silicon nitride, boron nitride, or magnesium oxide.Outer conductor 536 is a 1″ Schedule 80 446 stainless steel pipe. Outerconductor 536 is coupled to jacket 540. Jacket 540 is made fromcorrosion resistant material such as 347H stainless steel. In anembodiment, conductive layer 544 is placed between outer conductor 536and jacket 540. Conductive layer 544 is a copper layer. Heat is producedprimarily in outer conductor 536, resulting in a small temperaturedifferential across electrical insulator 534. Conductive layer 544allows a sharp decrease in the resistance of outer conductor 536 as theouter conductor approaches the Curie temperature and/or the phasetransformation temperature range. Jacket 540 provides protection fromcorrosive fluids in the wellbore.

In certain embodiments, inner conductor 532 includes a core of copper oranother non-ferromagnetic conductor surrounded by ferromagnetic material(for example, a low Curie temperature material such as Invar 36). Incertain embodiments, the copper core has an outer diameter between about0.125″ and about 0.375″ (for example, about 0.5″) and the ferromagneticmaterial has an outer diameter between about 0.625″ and about 1″ (forexample, about 0.75″). The copper core may increase the turndown ratioof the heater and/or reduce the thickness needed in the ferromagneticmaterial, which may allow a lower cost heater to be made. Electricalinsulator 534 may be magnesium oxide with an outer diameter betweenabout 1″ and about 1.2″ (for example, about 1.11″). Outer conductor 536may include non-ferromagnetic electrically conductive material with highmechanical strength such as 825 stainless steel. Outer conductor 536 mayhave an outer diameter between about 1.2″ and about 1.5″ (for example,about 1.33″). In certain embodiments, inner conductor 532 is a forwardcurrent path and outer conductor 536 is a return current path.Conductive layer 544 may include copper or another non-ferromagneticmaterial with an outer diameter between about 1.3″ and about 1.4″ (forexample, about 1.384″). Conductive layer 544 may decrease the resistanceof the return current path (to reduce the heat output of the return pathsuch that little or no heat is generated in the return path) and/orincrease the turndown ratio of the heater. Conductive layer 544 mayreduce the thickness needed in outer conductor 536 and/or jacket 540,which may allow a lower cost heater to be made. Jacket 540 may includeferromagnetic material such as carbon steel or 410 stainless steel withan outer diameter between about 1.6″ and about 1.8″ (for example, about1.684″). Jacket 540 may have a thickness of at least 2 times the skindepth of the ferromagnetic material in the jacket. Jacket 540 mayprovide protection from corrosive fluids in the wellbore. In someembodiments, inner conductor 532, electrical insulator 534, and outerconductor 536 are formed as composite heater (for example, an insulatedconductor heater) and conductive layer 544 and jacket 540 are formedaround (for example, wrapped) the composite heater and welded togetherto form the larger heater embodiment described herein.

In certain embodiments, jacket 540 includes ferromagnetic material thathas a higher Curie temperature than ferromagnetic material in innerconductor 532. Such a temperature limited heater may “contain” currentsuch that the current does not easily flow from the heater to thesurrounding formation and/or to any surrounding fluids (for example,production fluids, formation fluids, brine, groundwater, or formationwater). In this embodiment, a majority of the current flows throughinner conductor 532 until the Curie temperature of the ferromagneticmaterial in the inner conductor is reached. After the Curie temperatureof ferromagnetic material in inner conductor 532 is reached, a majorityof the current flows through the core of copper in the inner conductor.The ferromagnetic properties of jacket 540 inhibit the current fromflowing outside the jacket and “contain” the current. Such a heater maybe used in lower temperature applications where fluids are present suchas providing heat in a production wellbore to increase oil production.

In some embodiments, the conductor (for example, an inner conductor, anouter conductor, or a ferromagnetic conductor) is the compositeconductor that includes two or more different materials. In certainembodiments, the composite conductor includes two or more ferromagneticmaterials. In some embodiments, the composite ferromagnetic conductorincludes two or more radially disposed materials. In certainembodiments, the composite conductor includes a ferromagnetic conductorand a non-ferromagnetic conductor. In some embodiments, the compositeconductor includes the ferromagnetic conductor placed over anon-ferromagnetic core. Two or more materials may be used to obtain arelatively flat electrical resistivity versus temperature profile in atemperature region below the Curie temperature, and/or the phasetransformation temperature range, and/or a sharp decrease (a highturndown ratio) in the electrical resistivity at or near the Curietemperature and/or the phase transformation temperature range. In somecases, two or more materials are used to provide more than one Curietemperature and/or phase transformation temperature range for thetemperature limited heater.

The composite electrical conductor may be used as the conductor in anyelectrical heater embodiment described herein. For example, thecomposite conductor may be used as the conductor in aconductor-in-conduit heater or an insulated conductor heater. In certainembodiments, the composite conductor may be coupled to a support membersuch as a support conductor. The support member may be used to providesupport to the composite conductor so that the composite conductor isnot relied upon for strength at or near the Curie temperature and/or thephase transformation temperature range. The support member may be usefulfor heaters of lengths of at least 100 m. The support member may be anon-ferromagnetic member that has good high temperature creep strength.Examples of materials that are used for a support member include, butare not limited to, Haynes® 625 alloy and Haynes® HR120® alloy (HaynesInternational, Kokomo, Ind., U.S.A.), NF709, Incoloy® 800H alloy and347HP alloy (Allegheny Ludlum Corp., Pittsburgh, Pa., U.S.A.). In someembodiments, materials in a composite conductor are directly coupled(for example, brazed, metallurgically bonded, or swaged) to each otherand/or the support member. Using a support member may reduce the needfor the ferromagnetic member to provide support for the temperaturelimited heater, especially at or near the Curie temperature and/or thephase transformation temperature range. Thus, the temperature limitedheater may be designed with more flexibility in the selection offerromagnetic materials.

FIG. 65 depicts a cross-sectional representation of an embodiment of thecomposite conductor with the support member. Core 542 is surrounded byferromagnetic conductor 546 and support member 548. In some embodiments,core 542, ferromagnetic conductor 546, and support member 548 aredirectly coupled (for example, brazed together or metallurgically bondedtogether). In one embodiment, core 542 is copper, ferromagneticconductor 546 is 446 stainless steel, and support member 548 is 347Halloy. In certain embodiments, support member 548 is a Schedule 80 pipe.Support member 548 surrounds the composite conductor havingferromagnetic conductor 546 and core 542. Ferromagnetic conductor 546and core 542 may be joined to form the composite conductor by, forexample, a coextrusion process. For example, the composite conductor isa 1.9 cm outside diameter 446 stainless steel ferromagnetic conductorsurrounding a 0.95 cm diameter copper core.

In certain embodiments, the diameter of core 542 is adjusted relative toa constant outside diameter of ferromagnetic conductor 546 to adjust theturndown ratio of the temperature limited heater. For example, thediameter of core 542 may be increased to 1.14 cm while maintaining theoutside diameter of ferromagnetic conductor 546 at 1.9 cm to increasethe turndown ratio of the heater.

FIG. 66 depicts a cross-sectional representation of an embodiment of thecomposite conductor with support member 548 separating the conductors.In one embodiment, core 542 is copper with a diameter of 0.95 cm,support member 548 is 347H alloy with an outside diameter of 1.9 cm, andferromagnetic conductor 546 is 446 stainless steel with an outsidediameter of 2.7 cm. The support member depicted in FIG. 66 has a lowercreep strength relative to the support members depicted in FIG. 65.

In certain embodiments, support member 548 is located inside thecomposite conductor. FIG. 67 depicts a cross-sectional representation ofan embodiment of the composite conductor surrounding support member 548.Support member 548 is made of 347H alloy. Inner conductor 532 is copper.Ferromagnetic conductor 546 is 446 stainless steel. In one embodiment,support member 548 is 1.25 cm diameter 347H alloy, inner conductor 532is 1.9 cm outside diameter copper, and ferromagnetic conductor 546 is2.7 cm outside diameter 446 stainless steel. The turndown ratio ishigher than the turndown ratio for the embodiments depicted in FIGS. 65,66, and 68 for the same outside diameter, but the creep strength islower.

In some embodiments, the thickness of inner conductor 532, which iscopper, is reduced and the thickness of support member 548 is increasedto increase the creep strength at the expense of reduced turndown ratio.For example, the diameter of support member 548 is increased to 1.6 cmwhile maintaining the outside diameter of inner conductor 532 at 1.9 cmto reduce the thickness of the conduit. This reduction in thickness ofinner conductor 532 results in a decreased turndown ratio relative tothe thicker inner conductor embodiment but an increased creep strength.

FIG. 68 depicts a cross-sectional representation of an embodiment of thecomposite conductor surrounding support member 548. In one embodiment,support member 548 is 347H alloy with a 0.63 cm diameter center hole. Insome embodiments, support member 548 is a preformed conduit. In certainembodiments, support member 548 is formed by having a dissolvablematerial (for example, copper dissolvable by nitric acid) located insidethe support member during formation of the composite conductor. Thedissolvable material is dissolved to form the hole after the conductoris assembled. In an embodiment, support member 548 is 347H alloy with aninside diameter of 0.63 cm and an outside diameter of 1.6 cm, innerconductor 532 is copper with an outside diameter of 1.8 cm, andferromagnetic conductor 546 is 446 stainless steel with an outsidediameter of 2.7 cm.

In certain embodiments, the composite electrical conductor is used asthe conductor in the conductor-in-conduit heater. For example, thecomposite electrical conductor may be used as conductor 550 in FIG. 69.

FIG. 69 depicts a cross-sectional representation of an embodiment of theconductor-in-conduit heater. Conductor 550 is disposed in conduit 552.Conductor 550 is a rod or conduit of electrically conductive material.Low resistance sections 554 are present at both ends of conductor 550 togenerate less heating in these sections. Low resistance section 554 isformed by having a greater cross-sectional area of conductor 550 in thatsection, or the sections are made of material having less resistance. Incertain embodiments, low resistance section 554 includes a lowresistance conductor coupled to conductor 550.

Conduit 552 is made of an electrically conductive material. Conduit 552is disposed in opening 556 in hydrocarbon layer 484. Opening 556 has adiameter that accommodates conduit 552.

Conductor 550 may be centered in conduit 552 by centralizers 558.Centralizers 558 electrically isolate conductor 550 from conduit 552.Centralizers 558 inhibit movement and properly locate conductor 550 inconduit 552. Centralizers 558 are made of ceramic material or acombination of ceramic and metallic materials. Centralizers 558 inhibitdeformation of conductor 550 in conduit 552. Centralizers 558 aretouching or spaced at intervals between approximately 0.1 m (meters) andapproximately 3 m or more along conductor 550.

A second low resistance section 554 of conductor 550 may coupleconductor 550 to wellhead 476. Electrical current may be applied toconductor 550 from power cable 560 through low resistance section 554 ofconductor 550. Electrical current passes from conductor 550 throughsliding connector 562 to conduit 552. Conduit 552 may be electricallyinsulated from overburden casing 564 and from wellhead 476 to returnelectrical current to power cable 560. Heat may be generated inconductor 550 and conduit 552. The generated heat may radiate in conduit552 and opening 556 to heat at least a portion of hydrocarbon layer 484.

Overburden casing 564 may be disposed in overburden 482. In someembodiments, overburden casing 564 is surrounded by materials (forexample, reinforcing material and/or cement) that inhibit heating ofoverburden 482. Low resistance section 554 of conductor 550 may beplaced in overburden casing 564. Low resistance section 554 of conductor550 is made of, for example, carbon steel. Low resistance section 554 ofconductor 550 may be centralized in overburden casing 564 usingcentralizers 558. Centralizers 558 are spaced at intervals ofapproximately 6 m to approximately 12 m or, for example, approximately 9m along low resistance section 554 of conductor 550. In a heaterembodiment, low resistance sections 554 are coupled to conductor 550 byone or more welds. In other heater embodiments, low resistance sectionsare threaded, threaded and welded, or otherwise coupled to theconductor. Low resistance section 554 generates little or no heat inoverburden casing 564. Packing 566 may be placed between overburdencasing 564 and opening 556. Packing 566 may be used as a cap at thejunction of overburden 482 and hydrocarbon layer 484 to allow filling ofmaterials in the annulus between overburden casing 564 and opening 556.In some embodiments, packing 566 inhibits fluid from flowing fromopening 556 to surface 568.

FIG. 70 depicts a cross-sectional representation of an embodiment of aremovable conductor-in-conduit heat source. Conduit 552 may be placed inopening 556 through overburden 482 such that a gap remains between theconduit and overburden casing 564. Fluids may be removed from opening556 through the gap between conduit 552 and overburden casing 564.Fluids may be removed from the gap through conduit 570. Conduit 552 andcomponents of the heat source included in the conduit that are coupledto wellhead 476 may be removed from opening 556 as a single unit. Theheat source may be removed as a single unit to be repaired, replaced,and/or used in another portion of the formation.

For a temperature limited heater in which the ferromagnetic conductorprovides a majority of the resistive heat output below the Curietemperature and/or the phase transformation temperature range, amajority of the current flows through material with highly non-linearfunctions of magnetic field (H) versus magnetic induction (B). Thesenon-linear functions may cause strong inductive effects and distortionthat lead to decreased power factor in the temperature limited heater attemperatures below the Curie temperature and/or the phase transformationtemperature range. These effects may render the electrical power supplyto the temperature limited heater difficult to control and may result inadditional current flow through surface and/or overburden power supplyconductors. Expensive and/or difficult to implement control systems suchas variable capacitors or modulated power supplies may be used tocompensate for these effects and to control temperature limited heaterswhere the majority of the resistive heat output is provided by currentflow through the ferromagnetic material.

In certain temperature limited heater embodiments, the ferromagneticconductor confines a majority of the flow of electrical current to anelectrical conductor coupled to the ferromagnetic conductor when thetemperature limited heater is below or near the Curie temperature and/orthe phase transformation temperature range of the ferromagneticconductor. The electrical conductor may be a sheath, jacket, supportmember, corrosion resistant member, or other electrically resistivemember. In some embodiments, the ferromagnetic conductor confines amajority of the flow of electrical current to the electrical conductorpositioned between an outermost layer and the ferromagnetic conductor.The ferromagnetic conductor is located in the cross section of thetemperature limited heater such that the magnetic properties of theferromagnetic conductor at or below the Curie temperature and/or thephase transformation temperature range of the ferromagnetic conductorconfine the majority of the flow of electrical current to the electricalconductor. The majority of the flow of electrical current is confined tothe electrical conductor due to the skin effect of the ferromagneticconductor. Thus, the majority of the current is flowing through materialwith substantially linear resistive properties throughout most of theoperating range of the heater.

In certain embodiments, the ferromagnetic conductor and the electricalconductor are located in the cross section of the temperature limitedheater so that the skin effect of the ferromagnetic material limits thepenetration depth of electrical current in the electrical conductor andthe ferromagnetic conductor at temperatures below the Curie temperatureand/or the phase transformation temperature range of the ferromagneticconductor. Thus, the electrical conductor provides a majority of theelectrically resistive heat output of the temperature limited heater attemperatures up to a temperature at or near the Curie temperature and/orthe phase transformation temperature range of the ferromagneticconductor. In certain embodiments, the dimensions of the electricalconductor may be chosen to provide desired heat output characteristics.

Because the majority of the current flows through the electricalconductor below the Curie temperature and/or the phase transformationtemperature range, the temperature limited heater has a resistanceversus temperature profile that at least partially reflects theresistance versus temperature profile of the material in the electricalconductor. Thus, the resistance versus temperature profile of thetemperature limited heater is substantially linear below the Curietemperature and/or the phase transformation temperature range of theferromagnetic conductor if the material in the electrical conductor hasa substantially linear resistance versus temperature profile. Forexample, the temperature limited heater in which the majority of thecurrent flows in the electrical conductor below the Curie temperatureand/or the phase transformation temperature range may have a resistanceversus temperature profile similar to the profile shown in FIG. 336. Theresistance of the temperature limited heater has little or no dependenceon the current flowing through the heater until the temperature nearsthe Curie temperature and/or the phase transformation temperature range.The majority of the current flows in the electrical conductor ratherthan the ferromagnetic conductor below the Curie temperature and/or thephase transformation temperature range.

Resistance versus temperature profiles for temperature limited heatersin which the majority of the current flows in the electrical conductoralso tend to exhibit sharper reductions in resistance near or at theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor. For example, the reduction in resistanceshown in FIG. 336 is sharper than the reduction in resistance shown inFIG. 322. The sharper reductions in resistance near or at the Curietemperature and/or the phase transformation temperature range are easierto control than more gradual resistance reductions near the Curietemperature and/or the phase transformation temperature range becauselittle current is flowing through the ferromagnetic material.

In certain embodiments, the material and/or the dimensions of thematerial in the electrical conductor are selected so that thetemperature limited heater has a desired resistance versus temperatureprofile below the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic conductor.

Temperature limited heaters in which the majority of the current flowsin the electrical conductor rather than the ferromagnetic conductorbelow the Curie temperature and/or the phase transformation temperaturerange are easier to predict and/or control. Behavior of temperaturelimited heaters in which the majority of the current flows in theelectrical conductor rather than the ferromagnetic conductor below theCurie temperature and/or the phase transformation temperature range maybe predicted by, for example, the resistance versus temperature profileand/or the power factor versus temperature profile. Resistance versustemperature profiles and/or power factor versus temperature profiles maybe assessed or predicted by, for example, experimental measurements thatassess the behavior of the temperature limited heater, analyticalequations that assess or predict the behavior of the temperature limitedheater, and/or simulations that assess or predict the behavior of thetemperature limited heater.

In certain embodiments, assessed or predicted behavior of thetemperature limited heater is used to control the temperature limitedheater. The temperature limited heater may be controlled based onmeasurements (assessments) of the resistance and/or the power factorduring operation of the heater. In some embodiments, the power, orcurrent, supplied to the temperature limited heater is controlled basedon assessment of the resistance and/or the power factor of the heaterduring operation of the heater and the comparison of this assessmentversus the predicted behavior of the heater. In certain embodiments, thetemperature limited heater is controlled without measurement of thetemperature of the heater or a temperature near the heater. Controllingthe temperature limited heater without temperature measurementeliminates operating costs associated with downhole temperaturemeasurement. Controlling the temperature limited heater based onassessment of the resistance and/or the power factor of the heater alsoreduces the time for making adjustments in the power or current suppliedto the heater compared to controlling the heater based on measuredtemperature.

As the temperature of the temperature limited heater approaches orexceeds the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic conductor, reduction in theferromagnetic properties of the ferromagnetic conductor allowselectrical current to flow through a greater portion of the electricallyconducting cross section of the temperature limited heater. Thus, theelectrical resistance of the temperature limited heater is reduced andthe temperature limited heater automatically provides reduced heatoutput at or near the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic conductor. In certainembodiments, a highly electrically conductive member is coupled to theferromagnetic conductor and the electrical conductor to reduce theelectrical resistance of the temperature limited heater at or above theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor. The highly electrically conductive membermay be an inner conductor, a core, or another conductive member ofcopper, aluminum, nickel, or alloys thereof.

The ferromagnetic conductor that confines the majority of the flow ofelectrical current to the electrical conductor at temperatures below theCurie temperature and/or the phase transformation temperature range mayhave a relatively small cross section compared to the ferromagneticconductor in temperature limited heaters that use the ferromagneticconductor to provide the majority of resistive heat output up to or nearthe Curie temperature and/or the phase transformation temperature range.A temperature limited heater that uses the electrical conductor toprovide a majority of the resistive heat output below the Curietemperature and/or the phase transformation temperature range has lowmagnetic inductance at temperatures below the Curie temperature and/orthe phase transformation temperature range because less current isflowing through the ferromagnetic conductor as compared to thetemperature limited heater where the majority of the resistive heatoutput below the Curie temperature and/or the phase transformationtemperature range is provided by the ferromagnetic material. Magneticfield (H) at radius (r) of the ferromagnetic conductor is proportionalto the current (I) flowing through the ferromagnetic conductor and thecore divided by the radius, or:H∝I/r.  (EQN. 5)Since only a portion of the current flows through the ferromagneticconductor for a temperature limited heater that uses the outer conductorto provide a majority of the resistive heat output below the Curietemperature and/or the phase transformation temperature range, themagnetic field of the temperature limited heater may be significantlysmaller than the magnetic field of the temperature limited heater wherethe majority of the current flows through the ferromagnetic material.The relative magnetic permeability (μ) may be large for small magneticfields.

The skin depth (δ) of the ferromagnetic conductor is inverselyproportional to the square root of the relative magnetic permeability(μ):δ∝(1/μ)^(1/2).  (EQN. 6)Increasing the relative magnetic permeability decreases the skin depthof the ferromagnetic conductor. However, because only a portion of thecurrent flows through the ferromagnetic conductor for temperatures belowthe Curie temperature and/or the phase transformation temperature range,the radius (or thickness) of the ferromagnetic conductor may bedecreased for ferromagnetic materials with large relative magneticpermeabilities to compensate for the decreased skin depth while stillallowing the skin effect to limit the penetration depth of theelectrical current to the electrical conductor at temperatures below theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor. The radius (thickness) of the ferromagneticconductor may be between 0.3 mm and 8 mm, between 0.3 mm and 2 mm, orbetween 2 mm and 4 mm depending on the relative magnetic permeability ofthe ferromagnetic conductor. Decreasing the thickness of theferromagnetic conductor decreases costs of manufacturing the temperaturelimited heater, as the cost of ferromagnetic material tends to be asignificant portion of the cost of the temperature limited heater.Increasing the relative magnetic permeability of the ferromagneticconductor provides a higher turndown ratio and a sharper decrease inelectrical resistance for the temperature limited heater at or near theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor.

Ferromagnetic materials (such as purified iron or iron-cobalt alloys)with high relative magnetic permeabilities (for example, at least 200,at least 1000, at least 1×10⁴, or at least 1×10⁵) and/or high Curietemperatures (for example, at least 600° C., at least 700° C., or atleast 800° C.) tend to have less corrosion resistance and/or lessmechanical strength at high temperatures. The electrical conductor mayprovide corrosion resistance and/or high mechanical strength at hightemperatures for the temperature limited heater. Thus, the ferromagneticconductor may be chosen primarily for its ferromagnetic properties.

Confining the majority of the flow of electrical current to theelectrical conductor below the Curie temperature and/or the phasetransformation temperature range of the ferromagnetic conductor reducesvariations in the power factor. Because only a portion of the electricalcurrent flows through the ferromagnetic conductor below the Curietemperature and/or the phase transformation temperature range, thenon-linear ferromagnetic properties of the ferromagnetic conductor havelittle or no effect on the power factor of the temperature limitedheater, except at or near the Curie temperature and/or the phasetransformation temperature range. Even at or near the Curie temperatureand/or the phase transformation temperature range, the effect on thepower factor is reduced compared to temperature limited heaters in whichthe ferromagnetic conductor provides a majority of the resistive heatoutput below the Curie temperature and/or the phase transformationtemperature range. Thus, there is less or no need for externalcompensation (for example, variable capacitors or waveform modification)to adjust for changes in the inductive load of the temperature limitedheater to maintain a relatively high power factor.

In certain embodiments, the temperature limited heater, which confinesthe majority of the flow of electrical current to the electricalconductor below the Curie temperature and/or the phase transformationtemperature range of the ferromagnetic conductor, maintains the powerfactor above 0.85, above 0.9, or above 0.95 during use of the heater.Any reduction in the power factor occurs only in sections of thetemperature limited heater at temperatures near the Curie temperatureand/or the phase transformation temperature range. Most sections of thetemperature limited heater are typically not at or near the Curietemperature and/or the phase transformation temperature range duringuse. These sections have a high power factor that approaches 1.0. Thepower factor for the entire temperature limited heater is maintainedabove 0.85, above 0.9, or above 0.95 during use of the heater even ifsome sections of the heater have power factors below 0.85.

Maintaining high power factors allows for less expensive power suppliesand/or control devices such as solid state power supplies or SCRs(silicon controlled rectifiers). These devices may fail to operateproperly if the power factor varies by too large an amount because ofinductive loads. With the power factors maintained at high values;however, these devices may be used to provide power to the temperaturelimited heater. Solid state power supplies have the advantage ofallowing fine tuning and controlled adjustment of the power supplied tothe temperature limited heater.

In some embodiments, transformers are used to provide power to thetemperature limited heater. Multiple voltage taps may be made into thetransformer to provide power to the temperature limited heater. Multiplevoltage taps allow the current supplied to switch back and forth betweenthe multiple voltages. This maintains the current within a range boundby the multiple voltage taps.

The highly electrically conductive member, or inner conductor, increasesthe turndown ratio of the temperature limited heater. In certainembodiments, thickness of the highly electrically conductive member isincreased to increase the turndown ratio of the temperature limitedheater. In some embodiments, the thickness of the electrical conductoris reduced to increase the turndown ratio of the temperature limitedheater. In certain embodiments, the turndown ratio of the temperaturelimited heater is between 1.1 and 10, between 2 and 8, or between 3 and6 (for example, the turndown ratio is at least 1.1, at least 2, or atleast 3).

FIG. 71 depicts an embodiment of a temperature limited heater in whichthe support member provides a majority of the heat output below theCurie temperature and/or the phase transformation temperature range ofthe ferromagnetic conductor. Core 542 is an inner conductor of thetemperature limited heater. In certain embodiments, core 542 is a highlyelectrically conductive material such as copper or aluminum. In someembodiments, core 542 is a copper alloy that provides mechanicalstrength and good electrically conductivity such as a dispersionstrengthened copper. In one embodiment, core 542 is Glidcop® (SCM MetalProducts, Inc., Research Triangle Park, North Carolina, U.S.A.).Ferromagnetic conductor 546 is a thin layer of ferromagnetic materialbetween electrical conductor 572 and core 542. In certain embodiments,electrical conductor 572 is also support member 548. In certainembodiments, ferromagnetic conductor 546 is iron or an iron alloy. Insome embodiments, ferromagnetic conductor 546 includes ferromagneticmaterial with a high relative magnetic permeability. For example,ferromagnetic conductor 546 may be purified iron such as Armco ingotiron (AK Steel Ltd., United Kingdom). Iron with some impuritiestypically has a relative magnetic permeability on the order of 400.Purifying the iron by annealing the iron in hydrogen gas (H₂) at 1450°C. increases the relative magnetic permeability of the iron. Increasingthe relative magnetic permeability of ferromagnetic conductor 546 allowsthe thickness of the ferromagnetic conductor to be reduced. For example,the thickness of unpurified iron may be approximately 4.5 mm while thethickness of the purified iron is approximately 0.76 mm.

In certain embodiments, electrical conductor 572 provides support forferromagnetic conductor 546 and the temperature limited heater.Electrical conductor 572 may be made of a material that provides goodmechanical strength at temperatures near or above the Curie temperatureand/or the phase transformation temperature range of ferromagneticconductor 546. In certain embodiments, electrical conductor 572 is acorrosion resistant member. Electrical conductor 572 (support member548) may provide support for ferromagnetic conductor 546 and corrosionresistance. Electrical conductor 572 is made from a material thatprovides desired electrically resistive heat output at temperatures upto and/or above the Curie temperature and/or the phase transformationtemperature range of ferromagnetic conductor 546.

In an embodiment, electrical conductor 572 is 347H stainless steel. Insome embodiments, electrical conductor 572 is another electricallyconductive, good mechanical strength, corrosion resistant material. Forexample, electrical conductor 572 may be 304H, 316H, 347HH, NF709,Incoloy® 800H alloy (Inco Alloys International, Huntington, West Va.,U.S.A.), Haynes® HR120 alloy, or Inconel® 617 alloy.

In some embodiments, electrical conductor 572 (support member 548)includes different alloys in different portions of the temperaturelimited heater. For example, a lower portion of electrical conductor 572(support member 548) is 347H stainless steel and an upper portion of theelectrical conductor (support member) is NF709. In certain embodiments,different alloys are used in different portions of the electricalconductor (support member) to increase the mechanical strength of theelectrical conductor (support member) while maintaining desired heatingproperties for the temperature limited heater.

In some embodiments, ferromagnetic conductor 546 includes differentferromagnetic conductors in different portions of the temperaturelimited heater. Different ferromagnetic conductors may be used indifferent portions of the temperature limited heater to vary the Curietemperature and/or the phase transformation temperature range and, thus,the maximum operating temperature in the different portions. In someembodiments, the Curie temperature and/or the phase transformationtemperature range in an upper portion of the temperature limited heateris lower than the Curie temperature and/or the phase transformationtemperature range in a lower portion of the heater. The lower Curietemperature and/or the phase transformation temperature range in theupper portion increases the creep-rupture strength lifetime in the upperportion of the heater.

In the embodiment depicted in FIG. 71, ferromagnetic conductor 546,electrical conductor 572, and core 542 are dimensioned so that the skindepth of the ferromagnetic conductor limits the penetration depth of themajority of the flow of electrical current to the support member whenthe temperature is below the Curie temperature and/or the phasetransformation temperature range of the ferromagnetic conductor. Thus,electrical conductor 572 provides a majority of the electricallyresistive heat output of the temperature limited heater at temperaturesup to a temperature at or near the Curie temperature and/or the phasetransformation temperature range of ferromagnetic conductor 546. Incertain embodiments, the temperature limited heater depicted in FIG. 71is smaller (for example, an outside diameter of 3 cm, 2.9 cm, 2.5 cm, orless) than other temperature limited heaters that do not use electricalconductor 572 to provide the majority of electrically resistive heatoutput. The temperature limited heater depicted in FIG. 71 may besmaller because ferromagnetic conductor 546 is thin as compared to thesize of the ferromagnetic conductor needed for a temperature limitedheater in which the majority of the resistive heat output is provided bythe ferromagnetic conductor.

In some embodiments, the support member and the corrosion resistantmember are different members in the temperature limited heater. FIGS. 72and 73 depict embodiments of temperature limited heaters in which thejacket provides a majority of the heat output below the Curietemperature and/or the phase transformation temperature range of theferromagnetic conductor. In these embodiments, electrical conductor 572is jacket 540. Electrical conductor 572, ferromagnetic conductor 546,support member 548, and core 542 (in FIG. 72) or inner conductor 532 (inFIG. 73) are dimensioned so that the skin depth of the ferromagneticconductor limits the penetration depth of the majority of the flow ofelectrical current to the thickness of the jacket. In certainembodiments, electrical conductor 572 is a material that is corrosionresistant and provides electrically resistive heat output below theCurie temperature and/or the phase transformation temperature range offerromagnetic conductor 546. For example, electrical conductor 572 is825 stainless steel or 347H stainless steel. In some embodiments,electrical conductor 572 has a small thickness (for example, on theorder of 0.5 mm).

In FIG. 72, core 542 is highly electrically conductive material such ascopper or aluminum. Support member 548 is 347H stainless steel oranother material with good mechanical strength at or near the Curietemperature and/or the phase transformation temperature range offerromagnetic conductor 546.

In FIG. 73, support member 548 is the core of the temperature limitedheater and is 347H stainless steel or another material with goodmechanical strength at or near the Curie temperature and/or the phasetransformation temperature range of ferromagnetic conductor 546. Innerconductor 532 is highly electrically conductive material such as copperor aluminum.

In some embodiments, a relatively thin conductive layer is used toprovide the majority of the electrically resistive heat output of thetemperature limited heater at temperatures up to a temperature at ornear the Curie temperature and/or the phase transformation temperaturerange of the ferromagnetic conductor. Such a temperature limited heatermay be used as the heating member in an insulated conductor heater. Theheating member of the insulated conductor heater may be located inside asheath with an insulation layer between the sheath and the heatingmember.

FIGS. 74A and 74B depict cross-sectional representations of anembodiment of the insulated conductor heater with the temperaturelimited heater as the heating member. Insulated conductor 574 includescore 542, ferromagnetic conductor 546, inner conductor 532, electricalinsulator 534, and jacket 540. Core 542 is a copper core. Ferromagneticconductor 546 is, for example, iron or an iron alloy.

Inner conductor 532 is a relatively thin conductive layer ofnon-ferromagnetic material with a higher electrical conductivity thanferromagnetic conductor 546. In certain embodiments, inner conductor 532is copper. Inner conductor 532 may be a copper alloy. Copper alloystypically have a flatter resistance versus temperature profile than purecopper. A flatter resistance versus temperature profile may provide lessvariation in the heat output as a function of temperature up to theCurie temperature and/or the phase transformation temperature range. Insome embodiments, inner conductor 532 is copper with 6% by weight nickel(for example, CuNi6 or LOHM™). In some embodiments, inner conductor 532is CuNi10Fe1Mn alloy. Below the Curie temperature and/or the phasetransformation temperature range of ferromagnetic conductor 546, themagnetic properties of the ferromagnetic conductor confine the majorityof the flow of electrical current to inner conductor 532. Thus, innerconductor 532 provides the majority of the resistive heat output ofinsulated conductor 574 below the Curie temperature and/or the phasetransformation temperature range.

In certain embodiments, inner conductor 532 is dimensioned, along withcore 542 and ferromagnetic conductor 546, so that the inner conductorprovides a desired amount of heat output and a desired turndown ratio.For example, inner conductor 532 may have a cross-sectional area that isaround 2 or 3 times less than the cross-sectional area of core 542.Typically, inner conductor 532 has to have a relatively smallcross-sectional area to provide a desired heat output if the innerconductor is copper or copper alloy. In an embodiment with copper innerconductor 532, core 542 has a diameter of 0.66 cm, ferromagneticconductor 546 has an outside diameter of 0.91 cm, inner conductor 532has an outside diameter of 1.03 cm, electrical insulator 534 has anoutside diameter of 1.53 cm, and jacket 540 has an outside diameter of1.79 cm. In an embodiment with a CuNi6 inner conductor 532, core 542 hasa diameter of 0.66 cm, ferromagnetic conductor 546 has an outsidediameter of 0.91 cm, inner conductor 532 has an outside diameter of 1.12cm, electrical insulator 534 has an outside diameter of 1.63 cm, andjacket 540 has an outside diameter of 1.88 cm. Such insulated conductorsare typically smaller and cheaper to manufacture than insulatedconductors that do not use the thin inner conductor to provide themajority of heat output below the Curie temperature and/or the phasetransformation temperature range.

Electrical insulator 534 may be magnesium oxide, aluminum oxide, silicondioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. In certain embodiments, electrical insulator 534is a compacted powder of magnesium oxide. In some embodiments,electrical insulator 534 includes beads of silicon nitride.

In certain embodiments, a small layer of material is placed betweenelectrical insulator 534 and inner conductor 532 to inhibit copper frommigrating into the electrical insulator at higher temperatures. Forexample, a small layer of nickel (for example, about 0.5 mm of nickel)may be placed between electrical insulator 534 and inner conductor 532.

Jacket 540 is made of a corrosion resistant material such as, but notlimited to, 347 stainless steel, 347H stainless steel, 446 stainlesssteel, or 825 stainless steel. In some embodiments, jacket 540 providessome mechanical strength for insulated conductor 574 at or above theCurie temperature and/or the phase transformation temperature range offerromagnetic conductor 546. In certain embodiments, jacket 540 is notused to conduct electrical current.

For long vertical temperature limited heaters (for example, heaters atleast 300 m, at least 500 m, or at least 1 km in length), the hangingstress becomes important in the selection of materials for thetemperature limited heater. Without the proper selection of material,the support member may not have sufficient mechanical strength (forexample, creep-rupture strength) to support the weight of thetemperature limited heater at the operating temperatures of the heater.

In certain embodiments, materials for the support member are varied toincrease the maximum allowable hanging stress at operating temperaturesof the temperature limited heater and, thus, increase the maximumoperating temperature of the temperature limited heater. Altering thematerials of the support member affects the heat output of thetemperature limited heater below the Curie temperature and/or the phasetransformation temperature range because changing the materials changesthe resistance versus temperature profile of the support member. Incertain embodiments, the support member is made of more than onematerial along the length of the heater so that the temperature limitedheater maintains desired operating properties (for example, resistanceversus temperature profile below the Curie temperature and/or the phasetransformation temperature range) as much as possible while providingsufficient mechanical properties to support the heater. In someembodiments, transition sections are used between sections of the heaterto provide strength that compensates for the difference in temperaturebetween sections of the heater. In certain embodiments, one or moreportions of the temperature limited heater have varying outsidediameters and/or materials to provide desired properties for the heater.

In certain embodiments of temperature limited heaters, three temperaturelimited heaters are coupled together in a three-phase wye configuration.Coupling three temperature limited heaters together in the three-phasewye configuration lowers the current in each of the individualtemperature limited heaters because the current is split between thethree individual heaters. Lowering the current in each individualtemperature limited heater allows each heater to have a small diameter.The lower currents allow for higher relative magnetic permeabilities ineach of the individual temperature limited heaters and, thus, higherturndown ratios. In addition, there may be no return current path neededfor each of the individual temperature limited heaters. Thus, theturndown ratio remains higher for each of the individual temperaturelimited heaters than if each temperature limited heater had its ownreturn current path.

In the three-phase wye configuration, individual temperature limitedheaters may be coupled together by shorting the sheaths, jackets, orcanisters of each of the individual temperature limited heaters to theelectrically conductive sections (the conductors providing heat) attheir terminating ends (for example, the ends of the heaters at thebottom of a heater wellbore). In some embodiments, the sheaths, jackets,canisters, and/or electrically conductive sections are coupled to asupport member that supports the temperature limited heaters in thewellbore.

In certain embodiments, coupling multiple heaters (for example, mineralinsulated conductor heaters) to a single power source, such as atransformer, is advantageous. Coupling multiple heaters to a singletransformer may result in using fewer transformers to power heaters usedfor a treatment area as compared to using individual transformers foreach heater. Using fewer transformers reduces surface congestion andallows easier access to the heaters and surface components. Using fewertransformers reduces capital costs associated with providing power tothe treatment area. In some embodiments, at least 4, at least 5, atleast 10, at least 25 heaters, at least 35 heaters, or at least 45heaters are powered by a single transformer. Additionally, poweringmultiple heaters (in different heater wells) from the single transformermay reduce overburden losses because of reduced voltage and/or phasedifferences between each of the heater wells powered by the singletransformer. Powering multiple heaters from the single transformer mayinhibit current imbalances between the heaters because the heaters arecoupled to the single transformer.

To provide power to multiple heaters using the single transformer, thetransformer may have to provide power at higher voltages to carry thecurrent to each of the heaters effectively. In certain embodiments, theheaters are floating (ungrounded) heaters in the formation. Floating theheaters allows the heaters to operate at higher voltages. In someembodiments, the transformer provides power output of at least about 3kV, at least about 4 kV, at least about 5 kV, or at least about 6 kV.

FIG. 75 depicts a top view representation of heater 438 with threeinsulated conductors 574 in conduit 570. Heater 438 may be located in aheater well in the subsurface formation. Conduit 570 may be a sheath,jacket, or other enclosure around insulated conductors 574. Eachinsulated conductor 574 includes core 542, electrical insulator 534, andjacket 540. Insulated conductors 574 may be mineral insulated conductorswith core 542 being a copper alloy (for example, a copper-nickel alloysuch as Alloy 180), electrical insulator 534 being magnesium oxide, andjacket 540 being Incoloy® 825, copper, or stainless steel (for example347H stainless steel). In some embodiments, jacket 540 includes non-workhardenable metals so that the jacket is annealable.

In some embodiments, core 542 and/or jacket 540 include ferromagneticmaterials. In some embodiments, one or more insulated conductors 574 aretemperature limited heaters. In certain embodiments, the overburdenportion of insulated conductors 574 include high electrical conductivitymaterials in core 542 (for example, pure copper or copper alloys such ascopper with 3% silicon at a weld joint) so that the overburden portionsof the insulated conductors provide little or no heat output. In certainembodiments, conduit 570 includes non-corrosive materials and/or highstrength materials such as stainless steel. In one embodiment, conduit570 is 347H stainless steel.

Insulated conductors 574 may be coupled to the single transformer in athree-phase configuration (for example, a three-phase wyeconfiguration). Each insulated conductor 574 may be coupled to one phaseof the single transformer. In certain embodiments, the singletransformer is also coupled to a plurality of identical heaters 438 inother heater wells in the formation (for example, the single transformermay couple to 40 or more heaters in the formation). In some embodiments,the single transformer couples to at least 4, at least 5, at least 10,at least 15, or at least 25 additional heaters in the formation.

Electrical insulator 534′ may be located inside conduit 570 toelectrically insulate insulated conductors 574 from the conduit. Incertain embodiments, electrical insulator 534′ is magnesium oxide (forexample, compacted magnesium oxide). In some embodiments, electricalinsulator 534′ is silicon nitride (for example, silicon nitride blocks).Electrical insulator 534′ electrically insulates insulated conductors574 from conduit 570 so that at high operating voltages (for example, 3kV or higher), there is no arcing between the conductors and theconduit. In some embodiments, electrical insulator 534′ inside conduit570 has at least the thickness of electrical insulators 534 in insulatedconductors 574. The increased thickness of insulation in heater 438(from electrical insulators 534 and/or electrical insulator 534′)inhibits and may prevent current leakage into the formation from theheater. In some embodiments, electrical insulator 534′ spatially locatesinsulated conductors 574 inside conduit 570.

FIG. 76 depicts an embodiment of three-phase wye transformer 580 coupledto a plurality of heaters 438. For simplicity in the drawing, only fourheaters 438 are shown in FIG. 76. It is to be understood that severalmore heaters may be coupled to the transformer 580. As shown in FIG. 76,each leg (each insulated conductor) of each heater is coupled to onephase of transformer 580 and current is returned to the neutral orground of the transformer (for example, returned through conductor 582depicted in FIGS. 75 and 77).

Return conductor 582 may be electrically coupled to the ends ofinsulated conductors 574 (as shown in FIG. 77) current returns from theends of the insulated conductors to the transformer on the surface ofthe formation. Return conductor 582 may include high electricalconductivity materials such as pure copper, nickel, copper alloys, orcombinations thereof so that the return conductor provides little or noheat output. In some embodiments, return conductor 582 is a tubular (forexample, a stainless steel tubular) that allows an optical fiber to beplaced inside the tubular to be used for temperature and/or othermeasurement. In some embodiments, return conductor 582 is a smallinsulated conductor (for example, small mineral insulated conductor).Return conductor 582 may be coupled to the neutral or ground leg of thetransformer in a three-phase wye configuration. Thus, insulatedconductors 574 are electrically isolated from conduit 570 and theformation. Using return conductor 582 to return current to the surfacemay make coupling the heater to a wellhead easier. In some embodiments,current is returned using one or more of jackets 540, depicted in FIG.75. One or more jackets 540 may be coupled to cores 542 at the end ofthe heaters and return current to the neutral of the three-phase wyetransformer.

FIG. 77 depicts a side view representation of the end section of threeinsulated conductors 574 in conduit 570. The end section is the sectionof the heaters the furthest away from (distal from) the surface of theformation. The end section includes contactor section 576 coupled toconduit 570. In some embodiments, contactor section 576 is welded orbrazed to conduit 570. Termination 578 is located in contactor section576. Termination 578 is electrically coupled to insulated conductors 574and return conductor 582. Termination 578 electrically couples the coresof insulated conductors 574 to the return conductor 582 at the ends ofthe heaters.

In certain embodiments, heater 438, depicted in FIGS. 75 and 77,includes an overburden section using copper as the core of the insulatedconductors. The copper in the overburden section may be the samediameter as the cores used in the heating section of the heater. Thecopper in the overburden section may have a larger diameter than thecores in the heating section of the heater. Increasing the size of thecopper in the overburden section may decrease losses in the overburdensection of the heater.

Heaters that include three insulated conductors 574 in conduit 570, asdepicted in FIGS. 75 and 77, may be made in a multiple step process. Insome embodiments, the multiple step process is performed at the site ofthe formation or treatment area. In some embodiments, the multiple stepprocess is performed at a remote manufacturing site away from theformation. The finished heater is then transported to the treatmentarea.

Insulated conductors 574 may be pre-assembled prior to the bundlingeither on site or at a remote location. Insulated conductors 574 andreturn conductor 582 may be positioned on spools. A machine may drawinsulated conductors 574 and return conductor 582 from the spools at aselected rate. Preformed blocks of insulation material may be positionedaround return conductor 582 and insulated conductors 574. In anembodiment, two blocks are positioned around return conductor 582 andthree blocks are positioned around insulated conductors 574 to formelectrical insulator 534′. The insulated conductors and return conductormay be drawn or pushed into a plate of conduit material that has beenrolled into a tubular shape. The edges of the plate may be pressedtogether and welded (for example, by laser welding). After formingconduit 570 around electrical insulator 534′, the bundle of insulatedconductors 574, and return conductor 582, the conduit may be compactedagainst the electrical insulator 582 so that all of the components ofthe heater are pressed together into a compact and tightly fitting form.During the compaction, the electrical insulator may flow and fill anygaps inside the heater.

In some embodiments, heater 438 (which includes conduit 570 aroundelectrical insulator 534′ and the bundle of insulated conductors 574 andreturn conductor 582) is inserted into a coiled tubing tubular that isplaced in a wellbore in the formation. The coiled tubing tubular may beleft in place in the formation (left in during heating of the formation)or removed from the formation after installation of the heater. Thecoiled tubing tubular may allow for easier installation of heater 438into the wellbore.

In some embodiments, one or more components of heater 438 are varied(for example, removed, moved, or replaced) while the operation of theheater remains substantially identical. FIG. 78 depicts an embodiment ofheater 438 with three insulated cores 542 in conduit 570. In thisembodiment, electrical insulator 534′ surrounds cores 542 and returnconductor 582 in conduit 570. Cores 542 are located in conduit 570without an electrical insulator and jacket surrounding the cores. Cores542 are coupled to the single transformer in a three-phase wyeconfiguration with each core 542 coupled to one phase of thetransformer. Return conductor 582 is electrically coupled to the ends ofcores 542 and returns current from the ends of the cores to thetransformer on the surface of the formation.

FIG. 79 depicts an embodiment of heater 438 with three insulatedconductors 574 and insulated return conductor in conduit 570. In thisembodiment, return conductor 582 is an insulated conductor with core542, electrical insulator 534, and jacket 540. Return conductor 582 andinsulated conductors 574 are located in conduit 570 surrounded byelectrical insulator 534′. Return conductor 582 and insulated conductors574 may be the same size or different sizes. Return conductor 582 andinsulated conductors 574 operate substantially the same as in theembodiment depicted in FIGS. 75 and 77.

FIGS. 80 and 81 depict embodiments of three insulated conductors 574banded together. Heater 438 includes three insulated conductors 574coupled together in a spiral configuration. In other embodiments, six,nine, or multiples of three insulated conductors are coupled together.In certain embodiments, insulated conductors 574 are held together inthe spiral configuration with bands 584 that are periodically placedaround insulated conductors 574.

Banding insulated conductors 574 together instead of placing theconductors in a casing allows open spaces between the conductors toradiate heat to the formation, thus increasing the radiating surfacearea of heater 438. Banding insulated conductors 574 together mayimprove the insertion strength of heater 438.

In some embodiments, insulated conductors 574 are banded onto and aroundsupport member 586, as shown in FIG. 81. Support member 586 may providestructural support and/or increase the insertion strength of heater 438.In some embodiments, support member 586 includes a conduit used toprovide fluids and/or to remove fluids from heater 438. For example,oxidization inhibiting fluids may be provided to heater 438 throughsupport member 586. In some embodiments, other structures are used toprovide fluids and/or to remove fluids from heater 438.

Heater 438 may be provided power from single phase power sources (forexample, as depicted in FIG. 80), or from three-phase power sources (forexample, as depicted in FIG. 81) depending on desired operation of theheater. Support member 586 may provide electrical isolation forinsulated conductors 438 coupled to the three-phase power source. Thevoltage differentials on the surfaces (jackets) of insulated conductors574 in the three-phase embodiment may be reduced because of theproximity effect.

In some embodiments, optical sensor 588 is located at or near a centerof insulated conductors 574. Optical sensor 588 may be used to assessproperties of heater 438 such as, but not limited to, stress,temperature, and/or pressure. In some embodiments, support member 586includes a notch, as shown in FIG. 81, for insertion of optical sensor588. The notch may allow continuous insertion of optical sensor opticalsensor 588 during installation of heater 438.

In some embodiments, three insulated conductor heaters (for example,mineral insulated conductor heaters) are coupled together into a singleassembly. The single assembly may be built in long lengths and mayoperate at high voltages (for example, voltages of 4000 V nominal). Incertain embodiments, the individual insulated conductor heaters areenclosed in corrosive resistant jackets to resist damage from theexternal environment. The jackets may be, for example, seam weldedstainless steel armor similar to that used on type MC/CWCMC cable.

In some embodiments, three insulated conductor heaters are cabled andthe insulating filler added in conventional methods known in the art.The insulated conductor heaters may include one or more heater sectionsthat resistively heat and provide heat to formation adjacent to theheater sections. The insulated conductors may include one or more othersections that provide electricity to the heater sections with relativelysmall heat loss. The individual insulated conductor heaters may bewrapped with high temperature fiber tapes before being placed on atake-up reel (for example, a coiled tubing rig). The reel assembly maybe moved to another machine for application of an outer metallic sheathor outer protective conduit.

In some embodiments, the fillers include glass, ceramic or othertemperature resistant fibers that withstand operating temperature of760° C. or higher. In addition, the insulated conductor cables may bewrapped in multiple layers of a ceramic fiber woven tape material. Bywrapping the tape around the cabled insulated conductor heaters prior toapplication of the outer metallic sheath, electrical isolation isprovided between the insulated conductor heaters and the outer sheath.This electrical isolation inhibits leakage current from the insulatedconductor heaters passing into the subsurface formation and forces anyleakage currents to return directly to the power source on theindividual insulated conductor sheaths and/or on a lead-in conductor orlead-out conductor coupled to the insulated conductors. The lead-in orlead-out conductors may be coupled to the insulated conductors when theinsulated conductors are placed into an assembly with the outer metallicsheath.

In certain embodiments, the insulated conductor heaters are wrapped witha metallic tape or other type of tape instead of the high temperatureceramic fiber woven tape material. The metallic tape holds the insulatedconductor heaters together. A widely-spaced wide pitch spiral wrappingof a high temperature fiber rope may be wrapped around the insulatedconductor heaters. The fiber rope may provide electrical isolationbetween the insulated conductors and the outer sheath. The fiber ropemay be added at any stage during assembly. For example, the fiber ropemay be added as a part of the final assembly when the outer sheath isadded. Application of the fiber rope may be simpler than otherelectrical isolation methods because application of the fiber rope isdone with only a single layer of rope instead of multiple layers ofceramic tape. The fiber rope may be less expensive than multiple layersof ceramic tape. The fiber rope may increase heat transfer between theinsulated conductors and the outer sheath and/or reduce interferencewith any welding process used to weld the outer sheath around theinsulated conductors (for example, seam welding).

In certain embodiments, an insulated conductor or another type of heateris installed in a wellbore or opening in the formation using outertubing coupled to a coiled tubing rig. FIG. 82 depicts outer tubing 1128partially unspooled from coiled tubing rig 1804. Outer tubing 1128 maybe made of metal or polymeric material. Outer tubing 1128 may be aflexible conduit such as, for example, a tubing guide string or othercoiled tubing string. Heater 438 may be pushed into outer tubing 1128,as shown in FIG. 83. In certain embodiments, heater 438 is pushed intoouter tubing 1128 by pumping the heater into the outer tubing.

In certain embodiments, one or more flexible cups 1806 are coupled tothe outside of heater 438. Flexible cups 1806 may have a variety ofshapes and/or sizes but typically are shaped and sized to maintain atleast some pressure inside at least a portion of outer tubing 1128 asheater 438 is pushed or pumped into the outer tubing. For example,flexible cups 1806 may have flexible edges that provide limitedmechanical resistance as heater 438 is pushed into outer tubing 1128 butremain in contact with the inner walls of outer tubing 1128 as theheater is pushed so that pressure is maintained between the heater andthe outer tubing. Maintaining at least some pressure in outer tubing1128 between flexible cups 1806 allows heater 438 to be continuouslypushed into the outer tubing with lower pump pressures. Without flexiblecups 1806, higher pressures may be needed to push heater 438 into outertubing 1128. In some embodiments, cups 1806 allow some pressure to bereleased while maintaining some pressure in outer tubing 1128. Incertain embodiments, flexible cups 1806 are spaced to distribute pumpingforces optimally along heater 438 inside outer tubing 1128.

Heater 438 is pushed into outer tubing 1128 until the heater is fullyinserted into the outer tubing, as shown in FIG. 84. Drilling guide 696may be coupled to the end of heater 438. Heater 438, outer tubing 1128,and drilling guide 696 may be spooled onto coiled tubing rig 1804, asshown in FIG. 85. After heater 438, outer tubing 1128, and drillingguide 696 are spooled onto coiled tubing rig 1804, the assembly may betransported to a location for installation of the heater. For example,the assembly may be transported to the location of a subsurface heaterwellbore (opening).

FIG. 86 depicts coiled tubing rig 1804 being used to install heater 438and outer tubing 1128 into opening 556 using drilling guide 696. Incertain embodiments, opening 556 is an L-shaped opening or wellbore witha substantially horizontal or inclined portion in a hydrocarboncontaining layer of the formation. In such embodiments, heater 438 has aheating section that is placed in the substantially horizontally orinclined portion of opening 556 to be used to heat the hydrocarboncontaining layer. In some embodiments, opening 556 has a horizontal orinclined section that is at least about 1000 m in length, at least about1500 m in length, or at least about 2000 m in length. Overburden casing564 may be located around the outer walls of opening 556 in anoverburden section of the formation. In some embodiments, drilling fluidis left in opening 556 after the opening has been completed (the openinghas been drilled).

FIG. 87 depicts heater 438 and outer tubing 1128 installed in opening556. Gap 1808 may be left at or near the far end of heater 438 and outertubing 1128. Gap 1808 may allow for some heater expansion in opening 556after the heater is energized.

After heater 438 and outer tubing 1128 are installed in opening 556, theouter tubing may be removed from the opening to leave the heater inplace in the opening. FIG. 88 depicts outer tubing 1128 being removedfrom opening 556 while leaving heater 438 installed in the opening.Outer tubing 1128 is spooled back onto coiled tubing rig 1804 as theouter tubing is pulled off heater 438. In some embodiments, outer tubing1128 is pumped down to allow the outer tubing to be pulled off heater438.

FIG. 89 depicts outer tubing 1128 used to provide packing material 566into opening 556. As outer tubing 1128 reaches the “shoe” or bend inopening 556, the outer tubing may be used to provide packing materialinto the opening. The shoe of opening 556 may be located at or near thebottom of overburden casing 564. Packing material 566 may be provided(for example, pumped) through outer tubing 1128 and out the end of theouter tubing at the shoe of opening 556. Packing material 566 isprovided into opening 556 to seal off the opening around heater 438.Packing material 566 provides a barrier between the overburden sectionand heating section of opening 556. In certain embodiments, packingmaterial 566 is cement or another suitable plugging material. In someembodiments, outer tubing 1128 is continuously spooled while packingmaterial 566 is provided into opening 556. Outer tubing 1128 may bespooled slowly while packing material 566 is provided into opening 556to allow the packing material to settle into the opening properly.

After packing material 566 is provided into opening 556, outer tubing1128 is spooled further onto coiled tubing rig 1804, as shown in FIG.90. FIG. 91 depicts outer tubing 1128 spooled onto coiled tubing rig1804 with heater 438 installed in opening 556. In certain embodiments,flexible cups 1806 are spaced in the portion of opening 556 withoverburden casing 564 to facilitate adequate stand-off of heater 438 inthe overburden portion of the opening. Flexible cups 1806 mayelectrically insulate heater 438 from overburden casing 564. Forexample, flexible cups 1806 may space apart heater 438 and overburdencasing 564 such that they are not in physical contact with each other.

After outer tubing 1128 is removed from opening 556, wellhead 476 and/orother completions may be installed at the surface of the opening, asshown in FIG. 92. When heater 438 is energized to begin heating,flexible cups 1806 may begin to burn or melt off. Flexible cups 1806 maybegin to burn or melt off at relatively low temperatures during theheating process.

FIG. 93 depicts an embodiment of a heater in wellbore 742 in formation524. The heater includes insulated conductor 574 in conduit 552 withmaterial 590 between the insulated conductor and the conduit. In someembodiments, insulated conductor 574 is a mineral insulated conductor.Electricity supplied to insulated conductor 574 resistively heats theinsulated conductor. Insulated conductor conductively transfers heat tomaterial 590. Heat may transfer within material 590 by heat conductionand/or by heat convection. Radiant heat from insulated conductor 574and/or heat from material 590 transfers to conduit 552. Heat maytransfer to the formation from the heater by conductive or radiativeheat transfer from conduit 552. Material 590 may be molten metal, moltensalt, or other liquid. In some embodiments, a gas (for example,nitrogen, carbon dioxide, and/or helium) is in conduit 552 abovematerial 590. The gas may inhibit oxidation or other chemical changes ofmaterial 590. The gas may inhibit vaporization of material 590. U.S.Published Patent Application 2008-0078551 to DeVault et al., which isincorporated by reference as if fully set forth herein, describes asystem for placement in a wellbore, the system including a heater in aconduit with a liquid metal between the heater and the conduit forheating subterranean earth.

Insulated conductor 574 and conduit 552 may be placed in an opening in asubsurface formation. Insulated conductor 574 and conduit 552 may haveany orientation in a subsurface formation (for example, the insulatedconductor and conduit may be substantially vertical or substantiallyhorizontally oriented in the formation). Insulated conductor 574includes core 542, electrical insulator 534, and jacket 540. In someembodiments, core 542 is a copper core. In some embodiments, core 542includes other electrical conductors or alloys (for example, copperalloys). In some embodiments, core 542 includes a ferromagneticconductor so that insulated conductor 574 operates as a temperaturelimited heater. In some embodiments, core 542 does not include aferromagnetic conductor.

In some embodiments, core 542 of insulated conductor 574 is made of twoor more portions. The first portion may be placed adjacent to theoverburden. The first portion may be sized and/or made of a highlyconductive material so that the first portion does not resistively heatto a high temperature. One or more other portions of core 574 may besized and/or made of material that resistively heats to a hightemperature. These portions of core 574 may be positioned adjacent tosections of the formation that are to be heated by the heater. In someembodiments, the insulated conductor does not include a highlyconductive first portion. A lead in cable may be coupled to theinsulated conductor to supply electricity to the insulated conductor.

In some embodiments, core 542 of insulated conductor 574 is a highlyconductive material such as copper. Core 542 may be electrically coupledto jacket 540 at or near the end of the insulated conductor. In someembodiments, insulated conductor 574 is electrically coupled to conduit552. Electrical current supplied to insulated conductor 574 mayresistively heat core 542, jacket 540, material 590, and/or conduit 552.Resistive heating of core 542, jacket 540, material 590, and/or conduit552 generates heat that may transfer to the formation.

Electrical insulator 534 may be magnesium oxide, aluminum oxide, silicondioxide, beryllium oxide, boron nitride, silicon nitride, orcombinations thereof. In certain embodiments, electrical insulator 534is a compacted powder of magnesium oxide. In some embodiments,electrical insulator 534 includes beads of silicon nitride. In certainembodiments, a thin layer of material clad over core 542 to inhibit thecore from migrating into the electrical insulator at higher temperatures(i.e., to inhibit copper of the core from migrating into magnesium oxideof the insulation). For example, a small layer of nickel (for example,about 0.5 mm of nickel) may be clad on core 542.

In some embodiments, material 590 may be relatively corrosive. Jacket540 and/or at least the inside surface of conduit 552 may be made of acorrosion resistant material such as, but not limited to, nickel, AlloyN (Carpenter Metals), 347 stainless steel, 347H stainless steel, 446stainless steel, or 825 stainless steel. For example, conduit 552 may beplated or lined with nickel. In some embodiments, material 590 may berelatively non-corrosive. Jacket 540 and/or at least the inside surfaceof conduit 552 may be made of a material such as carbon steel.

In some embodiments, jacket 540 of insulated conductor 574 is not usedas the main return of electrical current for the insulated conductor. Inembodiments where material 590 is a good electrical conductor such as amolten metal, current returns through the molten metal in the conduitand/or through the conduit 552. In some embodiments, conduit 552 is madeof a ferromagnetic material, (for example 410 stainless steel). Conduit552 may function as a temperature limited heater until the temperatureof the conduit approaches, reaches or exceeds the Curie temperature orphase transition temperature of the conduit material.

In some embodiments, material 590 returns electrical current to thesurface from insulated conductor 574 (i.e., the material acts as thereturn or ground conductor for the insulated conductor). Material 590may provide a current path with low resistance so that a long insulatedconductor 574 is useable in conduit 552. The long heater may operate atlow voltages for the length of the heater due to the presence ofmaterial 590 that is conductive.

FIG. 94 depicts an embodiment of a portion of insulated conductor 574 inconduit 552 wherein material 590 is a good conductor (for example, aliquid metal) and current flow is indicated by the arrows. Current flowsdown core 542 and returns through jacket 540, material 590, and conduit552. Jacket 540 and conduit 552 may be at approximately constantpotential. Current flows radially from jacket 540 to conduit 552 throughmaterial 590. Material 590 may resistively heat. Heat from material 590may transfer through conduit 552 into the formation.

In embodiments where material 590 is partially electrically conductive(for example, the material is a molten salt), current returns mainlythrough jacket 540. All or a portion of the current that passes throughpartially conductive material 590 may pass to ground through conduit552.

In the embodiment depicted in FIG. 93, core 542 of insulated conductor574 has a diameter of about 1 cm, electrical insulator 534 has anoutside diameter of about 1.6 cm, and jacket 540 has an outside diameterof about 1.8 cm. In other embodiments, the insulated conductor issmaller. For example, core 542 has a diameter of about 0.5 cm,electrical insulator 534 has an outside diameter of about 0.8 cm, andjacket 540 has an outside diameter of about 0.9 cm. Other insulatedconductor geometries may be used. For the same size conduit 552, thesmaller geometry of insulated conductor 574 may result in a higheroperating temperature of the insulated conductor to achieve the sametemperature at the conduit. The smaller geometry insulated conductorsmay be significantly more economically favorable due to manufacturingcost, weight, and other factors.

Material 590 may be placed between the outside surface of insulatedconductor 574 and the inside surface of conduit 552. In certainembodiments, material 590 is placed in the conduit in a solid form asballs or pellets. Material 590 may melt below the operating temperaturesof insulated conductor 574. Material may melt above ambient subsurfaceformation temperatures. Material 590 may be placed in conduit 552 afterinsulated conductor 574 is placed in the conduit. In certainembodiments, material 590 is placed in conduit 574 as a liquid. Theliquid may be placed in conduit 552 before or after insulated conductor574 is placed in the conduit (for example, the molten liquid may bepoured into the conduit before or after the insulated conductor isplaced in the conduit). Additionally, material 590 may be placed inconduit 552 before or after insulated conductor 574 is energized (i.e.,supplied with electricity). Material 590 may be added to conduit 552 orremoved from the conduit after operation of the heater is initialized.Material 590 may be added to or removed from conduit 552 to maintain adesired head of fluid in the conduit. In some embodiments, the amount ofmaterial 590 in conduit 552 may be adjusted (i.e., added to or depleted)to adjust or balance the stresses on the conduit. Material 590 mayinhibit deformation of conduit 552. The head of material 590 in conduit552 may inhibit the formation from crushing or otherwise deforming theconduit should the formation expand against the conduit. The head offluid in conduit 552 allows the wall of the conduit to be relativelythin. Having thin conduits 552 may increase the economic viability ofusing multiple heaters of this type to heat portions of the formation.

Material 590 may support insulated conductor 574 in conduit 552. Thesupport provided by material 590 of insulated conductor 574 may allowfor the deployment of long insulated conductors as compared to insulatedconductors positioned only in a gas in a conduit without the use ofspecial metallurgy to accommodate the weight of the insulated conductor.In certain embodiments, insulated conductor 574 is buoyant in material590 in conduit 552. For example, insulated conductor may be buoyant inmolten metal. The buoyancy of insulated conductor 574 reduces creepassociated problems in long, substantially vertical heaters. A bottomweight or tie down may be coupled to the bottom of insulated conductor574 to inhibit the insulated conductor from floating in material 590.

Material 590 may remain a liquid at operating temperatures of insulatedconductor 574. In some embodiments, material 590 melts at temperaturesabove about 100° C., above about 200° C., or above about 300° C. Theinsulated conductor may operate at temperatures greater than 200° C.,greater than 400° C., greater than 600° C., or greater than 800° C. Incertain embodiments, material 590 provides enhanced heat transfer frominsulated conductor 574 to conduit 552 at or near the operatingtemperatures of the insulated conductor.

Material 590 may include metals such as tin, zinc, an alloy such as a60% by weight tin, 40% by weight zinc alloy; bismuth; indium; cadmium,aluminum; lead; and/or combinations thereof (for example, eutecticalloys of these metals such as binary or ternary alloys). In oneembodiment, material 590 is tin. Some liquid metals may be corrosive.The jacket of the insulated conductor and/or at least the inside surfaceof the canister may need to be made of a material that is resistant tothe corrosion of the liquid metal. The jacket of the insulated conductorand/or at least the inside surface of the conduit may be made ofmaterials that inhibit the molten metal from leaching materials from theinsulating conductor and/or the conduit to form eutectic compositions ormetal alloys. Molten metals may be highly thermal conductive, but mayblock radiant heat transfer from the insulated conductor and/or haverelatively small heat transfer by natural convection.

Material 590 may be or include molten salts such as solar salt, saltspresented in Table 1, or other salts. The molten salts may be infraredtransparent to aid in heat transfer from the insulated conductor to thecanister. In some embodiments, solar salt includes sodium nitrate andpotassium nitrate (for example, about 60% by weight sodium nitrate andabout 40% by weight potassium nitrate). Solar salt melts at about 220°C. and is chemically stable up to temperatures of about 593° C. Othersalts that may be used include, but are not limited to LiNO₃ (melttemperature (T_(m)) of 264° C. and a decomposition temperature of about600° C.) and eutectic mixtures such as 53% by weight KNO₃, 40% by weightNaNO₃ and 7% by weight NaNO₂ (T_(m) of about 142° C. and an upperworking temperature of over 500° C.); 45.5% by weight KNO₃ and 54.5% byweight NaNO₂ (T_(m) of about 142-145° C. and an upper workingtemperature of over 500° C.); or 50% by weight NaCl and 50% by weightSrCl₂ (T_(m) of about 19° C. and an upper working temperature of over1200° C.).

TABLE 1 Material T_(m) (° C.) T_(b) (° C.) Zn 420 907 CdBr₂ 568 863 CdI₂388 744 CuBr₂ 498 900 PbBr₂ 371 892 TlBr 460 819 TlF 326 826 ThI₄ 566837 SnF₂ 215 850 SnI₂ 320 714 ZnCl₂ 290 732

Some molten salts, such as solar salt, may be relatively non-corrosiveso that the conduit and/or the jacket may be made of relativelyinexpensive material (for example, carbon steel). Some molten salts mayhave good thermal conductivity, may have high heat density, and mayresult in large heat transfer by natural convection.

In fluid mechanics, the Rayleigh number is a dimensionless numberassociated with heat transfer in a fluid. When the Rayleigh number isbelow the critical value for the fluid, heat transfer is primarily inthe form of conduction; and when the Rayleigh number is above thecritical value, heat transfer is primarily in the form of convection.The Rayleigh number is the product of the Grashof number (whichdescribes the relationship between buoyancy and viscosity in a fluid)and the Prandtl number (which describes the relationship betweenmomentum diffusivity and thermal diffusivity). For the same sizeinsulated conductors in conduits, and where the temperature of theconduit is 500° C., the Rayleigh number for solar salt in the conduit isabout 10 times the Rayleigh number for tin in the conduit. The higherRayleigh number implies that the strength of natural convection in themolten solar salt is much stronger than the strength of the naturalconvection in molten tin. The stronger natural convection of molten saltmay distribute heat and inhibit the formation of hot spots at locationsalong the length of the conduit. Hot spots may be caused by coke buildup at isolated locations adjacent to or on the conduit, contact of theconduit by the formation at isolated locations, and/or other highthermal load situations.

Conduit 552 may be a carbon steel or stainless steel canister. In someembodiments, conduit 552 may include cladding on the outer surface toinhibit corrosion of the conduit by formation fluid. Conduit 552 mayinclude cladding on an inner surface of the conduit that is corrosionresistant to material 590 in the conduit. Cladding applied to conduit552 may be a coating and/or a liner. If the conduit contains a metalsalt, the inner surface of the conduit may include coating of nickel, orthe conduit may be or include a liner of a corrosion resistant metalsuch as Alloy N. If the conduit contains a molten metal, the conduit mayinclude a corrosion resistant metal liner or coating, and/or a ceramiccoating (for example, a porcelain coating or fired enamel coating). Inan embodiment, conduit 552 is a canister of 410 stainless steel with anoutside diameter of about 6 cm. Conduit 552 may not need a thick wallbecause material 590 may provide internal pressure that inhibitsdeformation or crushing of the conduit due to external stresses.

FIG. 95 depicts an embodiment of the heater positioned in wellbore 742of formation 524 with a portion of insulated conductor 574 and conduit552 oriented substantially horizontally in the formation. Material 590may provide a head in conduit 552 due to the pressure of the material.The pressure head may keep material 590 in conduit 552. The pressurehead may also provide internal pressure that inhibits deformation orcollapse of conduit 552 due to external stresses.

In some embodiments, two or more insulated conductors are placed in theconduit. In some embodiments, only one of the insulated conductors isenergized. Should the energized conductor fail, one of the otherconductors may be energized to maintain the material in a molten phase.The failed insulated conductor may be removed and/or replaced.

The conduit of the heater may be a ribbed conduit. The ribbed conduitmay improve the heat transfer characteristics of the conduit as comparedto a cylindrical conduit. FIG. 96 depicts a cross-sectionalrepresentation of ribbed conduit 592. FIG. 97 depicts a perspective viewof a portion of ribbed conduit 592. Ribbed conduit 592 may include rings594 and ribs 596. Rings 594 and ribs 596 may improve the heat transfercharacteristics of ribbed conduit 592. In an embodiment, the cylinder ofconduit has an inner diameter of about 5.1 cm and a wall thickness ofabout 0.57 cm. Rings 594 may be spaced about every 3.8 cm. Rings 594 mayhave a height of about 1.9 cm and a thickness of about 0.5 cm. Six ribs596 may be spaced evenly about conduit 552. Ribs 596 may have athickness of about 0.5 cm and a height of about 1.6 cm. Other dimensionsfor the cylinder, rings and ribs may be used. Ribbed conduit 592 may beformed from two or more rolled pieces that are welded together to formthe ribbed conduit. Other types of conduit with extra surface area toenhance heat transfer from the conduit to the formation may be used.

In some embodiments, the ribbed conduit may be used as the conduit of aconductor-in-conduit heater. For example, the conductor may be a 3.05 cm410 stainless steel rod and the conduit has dimensions as describedabove. In other embodiments, the conductor is an insulated conductor anda fluid is positioned between the conductor and the ribbed conduit. Thefluid may be a gas or liquid at operating temperatures of the insulatedconductor.

In some embodiments, the heat source for the heater is not an insulatedconductor. For example, the heat source may be hot fluid circulatedthrough an inner conduit positioned in an outer conduit. The materialmay be positioned between the inner conduit and the outer conduit.Convection currents in the material may help to more evenly distributeheat to the formation and may inhibit or limit formation of a hot spotwhere insulation that limits heat transfer to the overburden ends. Insome embodiments, the heat sources are downhole oxidizers. The materialis placed between an outer conduit and an oxidizer conduit. The oxidizerconduit may be an exhaust conduit for the oxidizers or the oxidantconduit if the oxidizers are positioned in a u-shaped wellbore withexhaust gases exiting the formation through one of the legs of theu-shaped conduit. The material may help inhibit the formation of hotspots adjacent to the oxidizers of the oxidizer assembly.

The material to be heated by the insulated conductor may be placed in anopen wellbore. FIG. 98 depicts material 590 in open wellbore 742 information 524 with insulated conductor 574 in the wellbore. In someembodiments, a gas (for example, nitrogen, carbon dioxide, and/orhelium) is placed in wellbore 742 above material 590. The gas mayinhibit oxidation or other chemical changes of material 590. The gas mayinhibit vaporization of material 590.

Material 590 may have a melting point that is above the pyrolysistemperature of hydrocarbons in the formation. The melting point ofmaterial 590 may be above 375° C., above 400° C., or above 425° C. Theinsulated conductor may be energized to heat the formation. Heat fromthe insulated conductor may pyrolyze hydrocarbons in the formation.Adjacent the wellbore, the heat from insulated conductor 574 may resultin coking that reduces the permeability and plugs the formation nearwellbore 742. The plugged formation inhibits material 590 from leakingfrom wellbore 742 into formation 524 when the material is a liquid. Insome embodiments, material 590 is a salt.

In some embodiments, material 590 leaking from wellbore 742 intoformation 524 may be self-healing and/or self-sealing. Material 590flowing away from wellbore 742 may travel until the temperature becomesless than the solidification temperature of the material. Temperaturemay drop rapidly a relatively small distance away from the heater usedto maintain material 590 in a liquid state. The rapid drop off intemperature may result in migrating material 590 solidifying close towellbore 742. Solidified material 590 may inhibit migration ofadditional material from wellbore 742, and thus self-heal and/orself-seal the wellbore.

Return electrical current for insulated conductor 574 may return throughjacket 540 of the insulated conductor. Any current that passes throughmaterial 590 may pass to ground. Above the level of material 590, anyremaining return electrical current may be confined to jacket 540 ofinsulated conductor 574.

Using liquid material in open wellbores heated by heaters may allow fordelivery of high power rates (for example, up to about 2000 W/m) to theformation with relatively low heater surface temperatures. Hot spotgeneration in the formation may be reduced or eliminated due toconvection smoothing out the temperature profile along the length of theheater. Natural convection occurring in the wellbore may greatly enhanceheat transfer from the heater to the formation. Also, the large gapbetween the formation and the heater may prevent thermal expansion ofthe formation from harming the heater.

In some embodiments, an 8″ (20.3 cm) wellbore may be formed in theformation. In some embodiments, casing may be placed through all or aportion of the overburden. A 0.6 inch (1.5 cm) diameter insulatedconductor heater may be placed in the wellbore. The wellbore may befilled with solid material (for example, solid particles of salt). Apacker may be placed near an interface between the treatment area andthe overburden. In some embodiments, a pass through conduit in thepacker may be included to allow for the addition of more material to thetreatment area. A non-reactive or substantially non-reactive gas (forexample, carbon dioxide and/or nitrogen) may be introduced into thewellbore. The insulated conductor may be energized to begin the heatingthat melts the solid material and heats the treatment area.

In some embodiments, other types of heat sources besides for insulatedconductors are used to heat the material placed in the open wellbore.The other types of heat sources may include gas burners, pipes throughwhich hot heat transfer fluid flows, or other types of heaters.

In some embodiments, heat pipes are placed in the formation. The heatpipes may reduce the number of active heat sources needed to heat atreatment area of a given size. The heat pipes may reduce the timeneeded to heat the treatment area of a given size to a desired averagetemperature. A heat pipe is a closed system that utilizes phase changeof fluid in the heat pipe to transport heat applied to a first region toa second region remote from the first region. The phase change of thefluid allows for large heat transfer rates. Heat may be applied to thefirst region of the heat pipes from any type of heat source, includingbut not limited to, electric heaters, oxidizers, heat provided fromgeothermal sources, and/or heat provided from nuclear reactors.

Heat pipes are passive heat transport systems that include no movingparts. Heat pipes may be positioned in near horizontal to verticalconfigurations. The fluid used in heat pipes for heating the formationmay have a low cost, a low melting temperature, a boiling temperaturethat is not too high (for example, generally below about 900° C.), a lowviscosity at temperatures below about 540° C., a high heat ofvaporization, and a low corrosion rate for the heat pipe material. Insome embodiments, the heat pipe includes a liner of material that isresistant to corrosion by the fluid. TABLE 1 shows melting and boilingtemperatures for several materials that may be used as the fluid in heatpipes. Other salts that may be used include, but are not limited toLiNO₃, and eutectic mixtures such as 53% by weight KNO₃; 40% by weightNaNO₃ and 7% by weight NaNO₂; 45.5% by weight KNO₃ and 54.5% by weightNaNO₂; or 50% by weight NaCl and 50% by weight SrCl₂.

FIG. 99 depicts schematic cross-sectional representation of a portion ofthe formation with heat pipes 598 positioned adjacent to a substantiallyhorizontal portion of heat source 202. Heat source 202 is placed in awellbore in the formation. Heat source 202 may be a gas burner assembly,an electrical heater, a leg of a circulation system that circulates hotfluid through the formation, or other type of heat source. Heat pipes598 may be placed in the formation so that distal ends of the heat pipesare near or contact heat source 202. In some embodiments, heat pipes 598mechanically attach to heat source 202. Heat pipes 598 may be spaced adesired distance apart. In an embodiment, heat pipes 598 are spacedapart by about 40 feet. In other embodiments, large or smaller spacingsare used. Heat pipes 598 may be placed in a regular pattern with eachheat pipe spaced a given distance from the next heat pipe. In someembodiments, heat pipes 598 are placed in an irregular pattern. Anirregular pattern may be used to provide a greater amount of heat to aselected portion or portions of the formation. Heat pipes 598 may bevertically positioned in the formation. In some embodiments, heat pipes598 are placed at an angle in the formation.

Heat pipes 598 may include sealed conduit 600, seal 602, liquid heattransfer fluid 604 and vaporized heat transfer fluid 606. In someembodiments, heat pipes 598 include metal mesh or wicking material thatincreases the surface area for condensation and/or promotes flow of theheat transfer fluid in the heat pipe. Conduit 600 may have first portion608 and second portion 610. Liquid heat transfer fluid 604 may be infirst portion 608. Heat source 202 external to heat pipe 598 suppliesheat that vaporizes liquid heat transfer fluid 604. Vaporized heattransfer fluid 606 diffuses into second portion 610. Vaporized heattransfer fluid 606 condenses in second portion and transfers heat toconduit 600, which in turn transfers heat to the formation. Thecondensed liquid heat transfer fluid 604 flows by gravity to firstportion 608.

Position of seal 602 is a factor in determining the effective length ofheat pipe 598. The effective length of heat pipe 598 may also depend onthe physical properties of the heat transfer fluid and thecross-sectional area of conduit 600. Enough heat transfer fluid may beplaced in conduit 600 so that some liquid heat transfer fluid 604 ispresent in first portion 608 at all times.

Seal 602 may provide a top seal for conduit 600. In some embodiments,conduit 600 is purged with nitrogen, helium or other fluid prior tobeing loaded with heat transfer fluid and sealed. In some embodiments, avacuum may be drawn on conduit 600 to evacuate the conduit before theconduit is sealed. Drawing a vacuum on conduit 600 before sealing theconduit may enhance vapor diffusion throughout the conduit. In someembodiments, an oxygen getter may be introduced in conduit 600 to reactwith any oxygen present in the conduit.

FIG. 100 depicts a perspective cut-out representation of a portion of aheat pipe embodiment with heat pipe 598 located radially around oxidizerassembly 612. Oxidizers 614 of oxidizer assembly 612 are positionedadjacent to first portion 608 of heat pipe 598. Fuel may be supplied tooxidizers 614 through fuel conduit 616. Oxidant may be supplied tooxidizers 614 through oxidant conduit 618. Exhaust gas may flow throughthe space between outer conduit 620 and oxidant conduit 618. Oxidizers614 combust fuel to provide heat that vaporizes liquid heat transferfluid 604. Vaporized heat transfer fluid 606 rises in heat pipe 598 andcondenses on walls of the heat pipe to transfer heat to sealed conduit600. Exhaust gas from oxidizers 614 provides heat along the length ofsealed conduit 600. The heat provided by the exhaust gas along theeffective length of heat pipe 598 may increase convective heat transferand/or reduce the lag time before significant heat is provided to theformation from the heat pipe along the effective length of the heatpipe.

FIG. 101 depicts a cross-sectional representation of an angled heat pipeembodiment with oxidizer assembly 612 located near a lowermost portionof heat pipe 598. Fuel may be supplied to oxidizers 614 through fuelconduit 616. Oxidant may be supplied to oxidizers 614 through oxidantconduit 618. Exhaust gas may flow through the space between outerconduit 620 and oxidant conduit 618.

FIG. 102 depicts a perspective cut-out representation of a portion of aheat pipe embodiment with oxidizer 614 located at the bottom of heatpipe 598. Fuel may be supplied to oxidizer 614 through fuel conduit 616.Oxidant may be supplied to oxidizer 614 through oxidant conduit 618.Exhaust gas may flow through the space between the outer wall of heatpipe 598 and outer conduit 620. Oxidizer 614 combusts fuel to provideheat that vaporizers liquid heat transfer fluid 604. Vaporized heattransfer fluid 606 rises in heat pipe 598 and condenses on walls of theheat pipe to transfer heat to sealed conduit 600. Exhaust gas fromoxidizers 614 provides heat along the length of sealed conduit 600 andto outer conduit 620. The heat provided by the exhaust gas along theeffective length of heat pipe 598 may increase convective heat transferand/or reduce the lag time before significant heat is provided to theformation from the heat pipe and oxidizer combination along theeffective length of the heat pipe. FIG. 103 depicts a similar embodimentwith heat pipe 598 positioned at an angle in the formation.

FIG. 104 depicts a perspective cut-out representation of a portion of aheat pipe embodiment with oxidizer 614 that produces flame zone adjacentto liquid heat transfer fluid 604 in the bottom of heat pipe 598. Fuelmay be supplied to oxidizer 614 through fuel conduit 616. Oxidant may besupplied to oxidizer 614 through oxidant conduit 618. Oxidant and fuelare mixed and combusted to produce flame zone 622. Flame zone 622provides heat that vaporizes liquid heat transfer fluid 604. Exhaustgases from oxidizer 614 may flow through the space between oxidantconduit 618 and the inner surface of heat pipe 598, and through thespace between the outer surface of the heat pipe and outer conduit 620.The heat provided by the exhaust gas along the effective length of heatpipe 598 may increase convective heat transfer and/or reduce the lagtime before significant heat is provided to the formation from the heatpipe and oxidizer combination along the effective length of the heatpipe.

FIG. 105 depicts a perspective cut-out representation of a portion of aheat pipe embodiment with a tapered bottom that accommodates multipleoxidizers of an oxidizer assembly. In some embodiments, efficient heatpipe operation requires a high heat input. Multiple oxidizers ofoxidizer assembly 612 may provide high heat input to liquid heattransfer fluid 604 of heat pipe 598. A portion of oxidizer assembly withthe oxidizers may be helically wound around a tapered portion of heatpipe 598. The tapered portion may have a large surface area toaccommodate the oxidizers. Fuel may be supplied to the oxidizers ofoxidizer assembly 612 through fuel conduit 616. Oxidant may be suppliedto oxidizer 614 through oxidant conduit 618. Exhaust gas may flowthrough the space between the outer wall of heat pipe 598 and outerconduit 620. Exhaust gas from oxidizers 614 provides heat along thelength of sealed conduit 600 and to outer conduit 620. The heat providedby the exhaust gas along the effective length of heat pipe 598 mayincrease convective heat transfer and/or reduce the lag time beforesignificant heat is provided to the formation from the heat pipe andoxidizer combination along the effective length of the heat pipe.

FIG. 106 depicts a cross-sectional representation of a heat pipeembodiment that is angled within the formation. First wellbore 624 andsecond wellbore 626 are drilled in the formation using magnetic rangingor techniques so that the first wellbore intersects the second wellbore.Heat pipe 598 may be positioned in first wellbore 624. First wellbore624 may be sloped so that liquid heat transfer fluid 604 within heatpipe 598 is positioned near the intersection of the first wellbore andsecond wellbore 626. Oxidizer assembly 612 may be positioned in secondwellbore 626. Oxidizer assembly 612 provides heat to heat pipe 598 thatvaporizes liquid heat transfer fluid in the heat pipe. Packer or seal628 may direct exhaust gas from oxidizer assembly 612 through firstwellbore 624 to provide additional heat to the formation from theexhaust gas.

In some embodiments, the temperature limited heater is used to achievelower temperature heating (for example, for heating fluids in aproduction well, heating a surface pipeline, or reducing the viscosityof fluids in a wellbore or near wellbore region). Varying theferromagnetic materials of the temperature limited heater allows forlower temperature heating. In some embodiments, the ferromagneticconductor is made of material with a lower Curie temperature than thatof 446 stainless steel. For example, the ferromagnetic conductor may bean alloy of iron and nickel. The alloy may have between 30% by weightand 42% by weight nickel with the rest being iron. In one embodiment,the alloy is Invar 36. Invar 36 is 36% by weight nickel in iron and hasa Curie temperature of 277° C. In some embodiments, an alloy is a threecomponent alloy with, for example, chromium, nickel, and iron. Forexample, an alloy may have 6% by weight chromium, 42% by weight nickel,and 52% by weight iron. A 2.5 cm diameter rod of Invar 36 has a turndownratio of approximately 2 to 1 at the Curie temperature. Placing theInvar 36 alloy over a copper core may allow for a smaller rod diameter.A copper core may result in a high turndown ratio. The insulator inlower temperature heater embodiments may be made of a high performancepolymer insulator (such as PFA or PEEK™) when used with alloys with aCurie temperature that is below the melting point or softening point ofthe polymer insulator.

In certain embodiments, a conductor-in-conduit temperature limitedheater is used in lower temperature applications by using lower Curietemperature and/or the phase transformation temperature rangeferromagnetic materials. For example, a lower Curie temperature and/orthe phase transformation temperature range ferromagnetic material may beused for heating inside sucker pump rods. Heating sucker pump rods maybe useful to lower the viscosity of fluids in the sucker pump or rodand/or to maintain a lower viscosity of fluids in the sucker pump rod.Lowering the viscosity of the oil may inhibit sticking of a pump used topump the fluids. Fluids in the sucker pump rod may be heated up totemperatures less than about 250° C. or less than about 300° C.Temperatures need to be maintained below these values to inhibit cokingof hydrocarbon fluids in the sucker pump system.

In certain embodiments, a temperature limited heater includes a flexiblecable (for example, a furnace cable) as the inner conductor. Forexample, the inner conductor may be a 27% nickel-clad or stainlesssteel-clad stranded copper wire with four layers of mica tape surroundedby a layer of ceramic and/or mineral fiber (for example, alumina fiber,aluminosilicate fiber, borosilicate fiber, or aluminoborosilicatefiber). A stainless steel-clad stranded copper wire furnace cable may beavailable from Anomet Products, Inc. The inner conductor may be ratedfor applications at temperatures of 1000° C. or higher. The innerconductor may be pulled inside a conduit. The conduit may be aferromagnetic conduit (for example, a ¾″ Schedule 80 446 stainless steelpipe). The conduit may be covered with a layer of copper, or otherelectrical conductor, with a thickness of about 0.3 cm or any othersuitable thickness. The assembly may be placed inside a support conduit(for example, a 1¼″ Schedule 80 347H or 347HH stainless steel tubular).The support conduit may provide additional creep-rupture strength andprotection for the copper and the inner conductor. For uses attemperatures greater than about 1000° C., the inner copper conductor maybe plated with a more corrosion resistant alloy (for example, Incoloy®825) to inhibit oxidation. In some embodiments, the top of thetemperature limited heater is sealed to inhibit air from contacting theinner conductor.

The temperature limited heater may be a single-phase heater or athree-phase heater. In a three-phase heater embodiment, the temperaturelimited heater has a delta or a wye configuration. Each of the threeferromagnetic conductors in the three-phase heater may be inside aseparate sheath. A connection between conductors may be made at thebottom of the heater inside a splice section. The three conductors mayremain insulated from the sheath inside the splice section.

FIG. 107 depicts an embodiment of a three-phase temperature limitedheater with ferromagnetic inner conductors. Each leg 632 has innerconductor 532, core 542, and jacket 540. Inner conductors 532 areferritic stainless steel or 1% carbon steel. Inner conductors 532 havecore 542. Core 542 may be copper. Each inner conductor 532 is coupled toits own jacket 540. Jacket 540 is a sheath made of a corrosion resistantmaterial (such as 304H stainless steel). Electrical insulator 534 isplaced between inner conductor 532 and jacket 540. Inner conductor 532is ferritic stainless steel or carbon steel with an outside diameter of1.14 cm and a thickness of 0.445 cm. Core 542 is a copper core with a0.25 cm diameter. Each leg 632 of the heater is coupled to terminalblock 634. Terminal block 634 is filled with insulation material 636 andhas an outer surface of stainless steel. In some embodiments, insulationmaterial 636 is silicon nitride, boron nitride, magnesium oxide or othersuitable electrically insulating material. Inner conductors 532 of legs632 are coupled (welded) in terminal block 634. Jackets 540 of legs 632are coupled (welded) to the outer surface of terminal block 634.Terminal block 634 may include two halves coupled around the coupledportions of legs 632.

In some embodiments, the three-phase heater includes three legs that arelocated in separate wellbores. The legs may be coupled in a commoncontacting section (for example, a central wellbore, a connectingwellbore, or a solution filled contacting section). FIG. 108 depicts anembodiment of temperature limited heaters coupled in a three-phaseconfiguration. Each leg 638, 640, 642 may be located in separateopenings 556 in hydrocarbon layer 484. Each leg 638, 640, 642 mayinclude heating element 644. Each leg 638, 640, 642 may be coupled tosingle contacting element 646 in one opening 556. Contacting element 646may electrically couple legs 638, 640, 642 together in a three-phaseconfiguration. Contacting element 646 may be located in, for example, acentral opening in the formation. Contacting element 646 may be locatedin a portion of opening 556 below hydrocarbon layer 484 (for example, inthe underburden). In certain embodiments, magnetic tracking of amagnetic element located in a central opening (for example, opening 556of leg 640) is used to guide the formation of the outer openings (forexample, openings 556 of legs 638 and 642) so that the outer openingsintersect the central opening. The central opening may be formed firstusing standard wellbore drilling methods. Contacting element 646 mayinclude funnels, guides, or catchers for allowing each leg to beinserted into the contacting element.

FIG. 109 depicts an embodiment of three heaters coupled in a three-phaseconfiguration. Conductor “legs” 638, 640, 642 are coupled to three-phasetransformer 648. Transformer 648 may be an isolated three-phasetransformer. In certain embodiments, transformer 648 providesthree-phase output in a wye configuration. Input to transformer 648 maybe made in any input configuration, such as the shown deltaconfiguration. Legs 638, 640, 642 each include lead-in conductors 650 inthe overburden of the formation coupled to heating elements 644 inhydrocarbon layer 484. Lead-in conductors 650 include copper with aninsulation layer. For example, lead-in conductors 650 may be a 4-0copper cables with TEFLON® insulation, a copper rod with polyurethaneinsulation, or other metal conductors such as bare copper or aluminum.In certain embodiments, lead-in conductors 650 are located in anoverburden portion of the formation. The overburden portion may includeoverburden casings 564. Heating elements 644 may be temperature limitedheater heating elements. In an embodiment, heating elements 644 are 410stainless steel rods (for example, 3.1 cm diameter 410 stainless steelrods). In some embodiments, heating elements 644 are compositetemperature limited heater heating elements (for example, 347 stainlesssteel, 410 stainless steel, copper composite heating elements; 347stainless steel, iron, copper composite heating elements; or 410stainless steel and copper composite heating elements). In certainembodiments, heating elements 644 have a length of about 10 m to about2000 m, about 20 m to about 400 m, or about 30 m to about 300 m.

In certain embodiments, heating elements 644 are exposed to hydrocarbonlayer 484 and fluids from the hydrocarbon layer. Thus, heating elements644 are “bare metal” or “exposed metal” heating elements. Heatingelements 644 may be made from a material that has an acceptablesulfidation rate at high temperatures used for pyrolyzing hydrocarbons.In certain embodiments, heating elements 644 are made from material thathas a sulfidation rate that decreases with increasing temperature overat least a certain temperature range (for example, 500° C. to 650° C.,530° C. to 650° C., or 550° C. to 650° C.). For example, 410 stainlesssteel may have a sulfidation rate that decreases with increasingtemperature between 530° C. and 650° C. Using such materials reducescorrosion problems due to sulfur-containing gases (such as H₂S) from theformation. In certain embodiments, heating elements 644 are made frommaterial that has a sulfidation rate below a selected value in atemperature range. In some embodiments, heating elements 644 are madefrom material that has a sulfidation rate at most about 25 mils per yearat a temperature between about 800° C. and about 880° C. In someembodiments, the sulfidation rate is at most about 35 mils per year at atemperature between about 800° C. and about 880° C., at most about 45mils per year at a temperature between about 800° C. and about 880° C.,or at most about 55 mils per year at a temperature between about 800° C.and about 880° C. Heating elements 644 may also be substantially inertto galvanic corrosion.

In some embodiments, heating elements 644 have a thin electricallyinsulating layer such as aluminum oxide or thermal spray coated aluminumoxide. In some embodiments, the thin electrically insulating layer is aceramic composition such as an enamel coating. Enamel coatings include,but are not limited to, high temperature porcelain enamels. Hightemperature porcelain enamels may include silicon dioxide, boron oxide,alumina, and alkaline earth oxides (CaO or MgO), and minor amounts ofalkali oxides (Na₂O, K₂O, LiO). The enamel coating may be applied as afinely ground slurry by dipping the heating element into the slurry orspray coating the heating element with the slurry. The coated heatingelement is then heated in a furnace until the glass transitiontemperature is reached so that the slurry spreads over the surface ofthe heating element and makes the porcelain enamel coating. Theporcelain enamel coating contracts when cooled below the glasstransition temperature so that the coating is in compression. Thus, whenthe coating is heated during operation of the heater, the coating isable to expand with the heater without cracking.

The thin electrically insulating layer has low thermal impedanceallowing heat transfer from the heating element to the formation whileinhibiting current leakage between heating elements in adjacent openingsand/or current leakage into the formation. In certain embodiments, thethin electrically insulating layer is stable at temperatures above atleast 350° C., above 500° C., or above 800° C. In certain embodiments,the thin electrically insulating layer has an emissivity of at least0.7, at least 0.8, or at least 0.9. Using the thin electricallyinsulating layer may allow for long heater lengths in the formation withlow current leakage.

Heating elements 644 may be coupled to contacting elements 646 at ornear the underburden of the formation. Contacting elements 646 arecopper or aluminum rods or other highly conductive materials. In certainembodiments, transition sections 652 are located between lead-inconductors 650 and heating elements 644, and/or between heating elements644 and contacting elements 646. Transition sections 652 may be made ofa conductive material that is corrosion resistant such as 347 stainlesssteel over a copper core. In certain embodiments, transition sections652 are made of materials that electrically couple lead-in conductors650 and heating elements 644 while providing little or no heat output.Thus, transition sections 652 help to inhibit overheating of conductorsand insulation used in lead-in conductors 650 by spacing the lead-inconductors from heating elements 644. Transition section 652 may have alength of between about 3 m and about 9 m (for example, about 6 m).

Contacting elements 646 are coupled to contactor 654 in contactingsection 656 to electrically couple legs 638, 640, 642 to each other. Insome embodiments, contact solution 658 (for example, conductive cement)is placed in contacting section 656 to electrically couple contactingelements 646 in the contacting section. In certain embodiments, legs638, 640, 642 are substantially parallel in hydrocarbon layer 484 andleg 638 continues substantially vertically into contacting section 656.The other two legs 640, 642 are directed (for example, by directionallydrilling the wellbores for the legs) to intercept leg 638 in contactingsection 656.

Each leg 638, 640, 642 may be one leg of a three-phase heater embodimentso that the legs are substantially electrically isolated from otherheaters in the formation and are substantially electrically isolatedfrom the formation. Legs 638, 640, 642 may be arranged in a triangularpattern so that the three legs form a triangular shaped three-phaseheater. In an embodiment, legs 638, 640, 642 are arranged in atriangular pattern with 12 m spacing between the legs (each side of thetriangle has a length of 12 m).

FIG. 110 depicts a side view representation of an embodiment ofcentralizer 558 on heater 438. FIG. 111 depicts an end viewrepresentation of the embodiment of centralizer 558 on heater 438depicted in FIG. 110. In certain embodiments, centralizers 558 are madeof three or more parts coupled to heater 438 so that the parts arespaced around the outside diameter of the heater. Having spaces betweenthe parts of a centralizer allows debris to fall along the heater (whenthe heater is vertical or substantially vertical) and inhibit debrisfrom collecting at the centralizer. In certain embodiments, thecentralizer is installed on a long heater without inserting a ring. Incertain embodiments, heater 438, as depicted in FIGS. 110 and 111, is anelectrical conductor used as part of a heater (for example, theelectrical conductor of a conductor-in-conduit heater). In certainembodiments, centralizer 558 includes three centralizer parts 558A,558B, and 558C. In other embodiments, centralizer 558 includes four ormore centralizer parts. Centralizer parts 558A, 558B, 558C may be evenlydistributed around the outside diameter of heater 438. Centralizer parts558A, 558B, 558C may have shapes that inhibit collection of materialand/or gouging of the canister that surrounds heater 438, even when thecentralizer parts are rotated in the canister. In some embodiments,upper portions of centralizer parts 558A, 558B, 558C may taper and/or berounded to inhibit accumulation of material on top of the centralizerparts.

In certain embodiments, centralizer parts 558A, 558B, 558C includeinsulators 660 and weld bases 662. Insulators 660 may be made ofelectrically insulating material such as, but not limited to, ceramic(for example, magnesium oxide) or silicon nitride. Weld bases 662 may bemade of weldable metal such as, but not limited to, Alloy 625, the samemetal used for heater 438, or another metal that may be brazed or solidstate welded to insulators 660 and welded to a metal used for heater438.

Weld bases 662 may be brazed or brazed to heater 438. In certainembodiments, insulators 660 are brazed, or otherwise coupled, to weldbases 662 to form centralizer parts 558A, 558B, 558C. Point loadtransfer between insulators 660 and weld bases 662 may be minimized bythe coupling. In some embodiments, weld bases 662 are coupled to heater438 first and then insulators 660 are coupled to the weld bases to formcentralizer parts 558A, 558B, 558C. Insulators 660 may be coupled toweld bases 662 as the heater is being installed into the formation. Insome embodiments, the bottoms of insulators 660 conform to the shape ofheater 438. In other embodiments, the bottoms of insulators 660 are flator have other geometries.

In certain embodiments, centralizer parts 558A, 558B, 558C are spacedevenly around the outside diameter of heater 438, as shown in FIGS. 110and 111. In other embodiments, centralizer parts 558A, 558B, 558C haveother spacings around the outside diameter of heater 438.

Having space between centralizer parts 558A, 558B, 558C allowsinstallation of the heaters and centralizers from a spool or coiledtubing installation of the heaters and centralizers. Centralizer parts558A, 558B, 558C also allow debris (for example, metal dust or pieces offormation) to fall along heater 438 through the area of the centralizer.Thus, debris is inhibited from collecting at or near centralizer 558. Inaddition, centralizer parts 558A, 558B, 558C may be inexpensive tomanufacture and install and easy to replace if broken.

FIG. 112 depicts a side view representation of an embodiment of asubstantially u-shaped three-phase heater. First ends of legs 638, 640,642 are coupled to transformer 648 at first location 664. In anembodiment, transformer 648 is a three-phase AC transformer. Ends oflegs 638, 640, 642 are electrically coupled together with connector 666at second location 668. Connector 666 electrically couples the ends oflegs 638, 640, 642 so that the legs can be operated in a three-phaseconfiguration. In certain embodiments, legs 638, 640, 642 are coupled tooperate in a three-phase wye configuration. In certain embodiments, legs638, 640, 642 are substantially parallel in hydrocarbon layer 484. Incertain embodiments, legs 638, 640, 642 are arranged in a triangularpattern in hydrocarbon layer 484. In certain embodiments, heatingelements 644 include thin electrically insulating material (such as aporcelain enamel coating) to inhibit current leakage from the heatingelements. In certain embodiments, the thin electrically insulating layerallows for relatively long, substantially horizontal heater leg lengthsin the hydrocarbon layer with a substantially u-shaped heater. Incertain embodiments, legs 638, 640, 642 are electrically coupled so thatthe legs are substantially electrically isolated from other heaters inthe formation and are substantially electrically isolated from theformation.

In certain embodiments, overburden casings (for example, overburdencasings 564, depicted in FIGS. 109 and 112) in overburden 482 includematerials that inhibit ferromagnetic effects in the casings. Inhibitingferromagnetic effects in casings 564 reduces heat losses to theoverburden. In some embodiments, casings 564 may include non-metallicmaterials such as fiberglass, polyvinylchloride (PVC), chlorinatedpolyvinylchloride (CPVC), or high-density polyethylene (HDPE). HDPEswith working temperatures in a range for use in overburden 482 includeHDPEs available from Dow Chemical Co., Inc. (Midland, Mich., U.S.A.). Anon-metallic casing may also eliminate the need for an insulatedoverburden conductor. In some embodiments, casings 564 include carbonsteel coupled on the inside diameter of a non-ferromagnetic metal (forexample, carbon steel clad with copper or aluminum) to inhibitferromagnetic effects or inductive effects in the carbon steel. Othernon-ferromagnetic metals include, but are not limited to, manganesesteels with at least 10% by weight manganese, iron aluminum alloys withat least 18% by weight aluminum, and austenitic stainless steels such as304 stainless steel or 316 stainless steel.

In certain embodiments, one or more non-ferromagnetic materials used incasings 564 are used in a wellhead coupled to the casings and legs 638,640, 642. Using non-ferromagnetic materials in the wellhead inhibitsundesirable heating of components in the wellhead. In some embodiments,a purge gas (for example, carbon dioxide, nitrogen or argon) isintroduced into the wellhead and/or inside of casings 564 to inhibitreflux of heated gases into the wellhead and/or the casings.

In certain embodiments, one or more of legs 638, 640, 642 are installedin the formation using coiled tubing. In certain embodiments, coiledtubing is installed in the formation, the leg is installed inside thecoiled tubing, and the coiled tubing is pulled out of the formation toleave the leg installed in the formation. The leg may be placedconcentrically inside the coiled tubing. In some embodiments, coiledtubing with the leg inside the coiled tubing is installed in theformation and the coiled tubing is removed from the formation to leavethe leg installed in the formation. The coiled tubing may extend only toa junction of the hydrocarbon layer and the contacting section, or to apoint at which the leg begins to bend in the contacting section.

FIG. 113 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in the formation. Each triad670 includes legs A, B, C (which may correspond to legs 638, 640, 642depicted in FIGS. 109 and 112) that are electrically coupled by linkages674. Each triad 670 is coupled to its own electrically isolatedthree-phase transformer so that the triads are substantiallyelectrically isolated from each other. Electrically isolating the triadsinhibits net current flow between triads.

The phases of each triad 670 may be arranged so that legs A, B, Ccorrespond between triads as shown in FIG. 113. Legs A, B, C arearranged such that a phase leg (for example, leg A) in a given triad isabout two triad heights from a same phase leg (leg A) in an adjacenttriad. The triad height is the distance from a vertex of the triad to amidpoint of the line intersecting the other two vertices of the triad.In certain embodiments, the phases of triads 670 are arranged to inhibitnet current flow between individual triads. There may be some leakage ofcurrent within an individual triad but little net current flows betweentwo triads due to the substantial electrical isolation of the triadsand, in certain embodiments, the arrangement of the triad phases.

In the early stages of heating, an exposed heating element (for example,heating element 644 depicted in FIGS. 109 and 112) may leak some currentto water or other fluids that are electrically conductive in theformation so that the formation itself is heated. After water or otherelectrically conductive fluids are removed from the wellbore (forexample, vaporized or produced), the heating elements becomeelectrically isolated from the formation. Later, when water is removedfrom the formation, the formation becomes even more electricallyresistant and heating of the formation occurs even more predominantlyvia thermally conductive and/or radiative heating. Typically, theformation (the hydrocarbon layer) has an initial electrical resistancethat averages at least 10 ohm m. In some embodiments, the formation hasan initial electrical resistance of at least 100 ohm·m or of at least300 ohm m.

Using the temperature limited heaters as the heating elements limits theeffect of water saturation on heater efficiency. With water in theformation and in heater wellbores, there is a tendency for electricalcurrent to flow between heater elements at the top of the hydrocarbonlayer where the voltage is highest and cause uneven heating in thehydrocarbon layer. This effect is inhibited with temperature limitedheaters because the temperature limited heaters reduce localizedoverheating in the heating elements and in the hydrocarbon layer.

In certain embodiments, production wells are placed at a location atwhich there is relatively little or zero voltage potential. Thislocation minimizes stray potentials at the production well. Placingproduction wells at such locations improves the safety of the system andreduces or inhibits undesired heating of the production wells caused byelectrical current flow in the production wells. FIG. 114 depicts a topview representation of the embodiment depicted in FIG. 113 withproduction wells 206. In certain embodiments, production wells 206 arelocated at or near center of triad 670. In certain embodiments,production wells 206 are placed at a location between triads at whichthere is relatively little or zero voltage potential (at a location atwhich voltage potentials from vertices of three triads average out torelatively little or zero voltage potential). For example, productionwell 206 may be at a location equidistant from leg A of one triad, leg Bof a second triad, and leg C of a third triad, as shown in FIG. 114.

FIG. 115 depicts a top view representation of an embodiment of aplurality of triads of three-phase heaters in a hexagonal pattern in theformation. FIG. 116 depicts a top view representation of an embodimentof a hexagon from FIG. 115. Hexagon 672 includes two triads of heaters.The first triad includes legs A1, B1, C1 electrically coupled togetherby linkages 674 in a three-phase configuration. The second triadincludes legs A2, B2, C2 electrically coupled together by linkages 674in a three-phase configuration. The triads are arranged so thatcorresponding legs of the triads (for example, A1 and A2, B1 and B2, C1and C2) are at opposite vertices of hexagon 672. The triads areelectrically coupled and arranged so that there is relatively little orzero voltage potential at or near the center of hexagon 672.

Production well 206 may be placed at or near the center of hexagon 672.Placing production well 206 at or near the center of hexagon 672 placesthe production well at a location that reduces or inhibits undesiredheating due to electromagnetic effects caused by electrical current flowin the legs of the triads and increases the safety of the system. Havingtwo triads in hexagon 672 provides for redundant heating aroundproduction well 206. Thus, if one triad fails or has to be turned off,production well 206 still remains at a center of one triad.

As shown in FIG. 115, hexagons 672 may be arranged in a pattern in theformation such that adjacent hexagons are offset. Using electricallyisolated transformers on adjacent hexagons may inhibit electricalpotentials in the formation so that little or no net current leaksbetween hexagons.

Triads of heaters and/or heater legs may be arranged in any shape ordesired pattern. For example, as described above, triads may includethree heaters and/or heater legs arranged in an equilateral triangularpattern. In some embodiments, triads include three heaters and/or heaterlegs arranged in other triangular shapes (for example, an isoscelestriangle or a right angle triangle). In some embodiments, heater legs inthe triad cross each other (for example, criss-cross) in the formation.In certain embodiments, triads includes three heaters and/or heater legsarranged sequentially along a straight line.

Distal sections of the heater legs may be electrically coupled together.The distal sections may be electrically coupled to a connector or toeach other. In certain embodiments, contacting elements of the heaterlegs are physically coupled to establish the electrical coupling. Forexample, heater legs may be electrically coupled by soldering, bywelding, by explosive crimping, by interconnecting brush contacts and/orby other techniques that involve physically attaching the legs to eachother or to a connector. In some embodiments, the contacting elements ofthe heater legs are placed in a contacting solution or otherelectrically conductive material to electrically couple the heater legstogether.

FIG. 117 depicts an embodiment with triads coupled to a horizontalconnector well. Triad 670A includes legs 638A, 640A, 642A. Triad 670Bincludes legs 638B, 640B, 642B. Legs 638A, 640A, 642A and legs 638B,640B, 642B may be arranged along a straight line on the surface of theformation. In some embodiments, legs 638A, 640A, 642A are arranged alonga straight line and offset from legs 638B, 640B, 642B, which may bearranged along a straight line. Legs 638A, 640A, 642A and legs 638B,640B, 642B include heating elements 644 located in hydrocarbon layer484. Lead-in conductors 650 couple heating elements 644 to the surfaceof the formation. Heating elements 644 are coupled to contactingelements 646 at or near the underburden of the formation. In certainembodiments, transition sections (for example, transition sections 652depicted in FIG. 109) are located between lead-in conductors 650 andheating elements 644, and/or between heating elements 644 and contactingelements 646.

Contacting elements 646 are coupled to contactor 654 in contactingsection 656 to electrically couple legs 638A, 640A, 642A to each otherto form triad 670A and electrically couple legs 638B, 640B, 642B to eachother to form triad 670B. In certain embodiments, contactor 654 is aground conductor so that triad 670A and/or triad 670B may be coupled inthree-phase wye configurations. In certain embodiments, triad 670A andtriad 670B are electrically isolated from each other. In someembodiments, triad 670A and triad 670B are electrically coupled to eachother (for example, electrically coupled in series or parallel).

In certain embodiments, contactor 654 is a substantially horizontalcontactor located in contacting section 656. Contactor 654 may be acasing or a solid rod placed in a wellbore drilled substantiallyhorizontally in contacting section 656. Legs 638A, 640A, 642A and legs638B, 640B, 642B may be electrically coupled to contactor 654 by anymethod described herein or any method known in the art. For example,containers with thermite powder are coupled to contactor 654 (forexample, by welding or brazing the containers to the contactor); legs638A, 640A, 642A and legs 638B, 640B, 642B are placed inside thecontainers; and the thermite powder is activated to electrically couplethe legs to the contactor. The containers may be coupled to contactor654 by, for example, placing the containers in holes or recesses incontactor 654 or coupled to the outside of the contactor and thenbrazing or welding the containers to the contactor.

In certain embodiments, two legs in separate wellbores intercept in asingle contacting section. FIG. 118 depicts an embodiment of twotemperature limited heaters coupled in a single contacting section. Legs638 and 640 include one or more heating elements 644. Heating elements644 may include one or more electrical conductors. In certainembodiments, legs 638 and 640 are electrically coupled in a single-phaseconfiguration with one leg positively biased versus the other leg sothat current flows downhole through one leg and returns through theother leg.

Heating elements 644 in legs 638 and 640 may be temperature limitedheaters. In certain embodiments, heating elements 644 are solid rodheaters. For example, heating elements 644 may be rods made of a singleferromagnetic conductor element or composite conductors that includeferromagnetic material. During initial heating when water is present inthe formation being heated, heating elements 644 may leak current intohydrocarbon layer 484. The current leaked into hydrocarbon layer 484 mayresistively heat the hydrocarbon layer.

In some embodiments (for example, in oil shale formations), heatingelements 644 do not need support members. Heating elements 644 may bepartially or slightly bent, curved, made into an S-shape, or made into ahelical shape to allow for expansion and/or contraction of the heatingelements. In certain embodiments, solid rod heating elements 644 areplaced in small diameter wellbores (for example, about 3¾″ (about 9.5cm) diameter wellbores). Small diameter wellbores may be less expensiveto drill or form than larger diameter wellbores, and there will be lesscuttings to dispose of.

In certain embodiments, portions of legs 638 and 640 in overburden 482have insulation (for example, polymer insulation) to inhibit heating theoverburden. Heating elements 644 may be substantially vertical andsubstantially parallel to each other in hydrocarbon layer 484. At ornear the bottom of hydrocarbon layer 484, leg 638 may be directionallydrilled towards leg 640 to intercept leg 640 in contacting section 656.Drilling two wellbores to intercept each other may be easier and lessexpensive than drilling three or more wellbores to intercept each other.The depth of contacting section 656 depends on the length of bend in leg638 needed to intercept leg 640. For example, for a 40 ft (about 12 m)spacing between vertical portions of legs 638 and 640, about 200 ft(about 61 m) is needed to allow the bend of leg 638 to intercept leg640. Coupling two legs may require a thinner contacting section 656 thancoupling three or more legs in the contacting section.

FIG. 119 depicts an embodiment for coupling legs 638 and 640 incontacting section 656. Heating elements 644 are coupled to contactingelements 646 at or near junction of contacting section 656 andhydrocarbon layer 484. Contacting elements 646 may be copper or anothersuitable electrical conductor. In certain embodiments, contactingelement 646 in leg 640 is a liner with opening 676. Contacting element646 from leg 638 passes through opening 676. Contactor 654 is coupled tothe end of contacting element 646 from leg 638. Contactor 654 provideselectrical coupling between contacting elements in legs 638 and 640.

In certain embodiments, contacting elements 646 include one or more finsor projections. The fins or projections may increase an electricalcontact area of contacting elements 646. In some embodiments, contactingelement 646 of leg 640 has an opening or other orifice that allows thecontacting element of 638 to couple to the contacting element of leg640.

In certain embodiments, legs 638 and 640 are coupled together to form adiad. Three diads may be coupled to a three-phase transformer to powerthe legs of the heaters. FIG. 120 depicts an embodiment of three diadscoupled to a three-phase transformer. In certain embodiments,transformer 648 is a delta three-phase transformer. Diad 678A includeslegs 638A and 640A. Diad 678B includes legs 638B and 640B. Diad 678Cincludes legs 638C and 640C. Diads 678A, 678B, 678C are coupled to thesecondaries of transformer 648. Diad 678A is coupled to the “A”secondary. Diad 678B is coupled to the “B” secondary. Diad 678C iscoupled to the “C” secondary.

Coupling the diads to the secondaries of the delta three-phasetransformer isolates the diads from ground. Isolating the diads fromground inhibits leakage to the formation from the diads. Coupling thediads to different phases of the delta three-phase transformer alsoinhibits leakage between the heating legs of the diads in the formation.

In some embodiments, diads are used for treating formations usingtriangular or hexagonal heater patterns. FIG. 121 depicts an embodimentof groups of diads in a hexagonal pattern. Heaters may be placed at thevertices of each of the hexagons in the hexagonal pattern. Each group680 of diads (enclosed by dashed circles) may be coupled to a separatethree-phase transformer. “A”, “B”, and “C” inside groups 680 representeach diad (for example, diads 678A, 678B, 678C depicted in FIG. 120)that is coupled to each of the three secondary phases of the transformerwith each phase coupled to one diad (with the heaters at the vertices ofthe hexagon). The numbers “1”, “2”, and “3” inside the hexagonsrepresent the three repeating types of hexagons in the pattern depictedin FIG. 121.

FIG. 122 depicts an embodiment of diads in a triangular pattern. Threediads 678A, 678B, 678C may be enclosed in each group 680 of diads(enclosed by dashed rectangles). Each group 680 may be coupled to aseparate three-phase transformer.

In certain embodiments, exposed metal heating elements are used insubstantially horizontal sections of u-shaped wellbores. Substantiallyu-shaped wellbores may be used in tar sands formations, oil shaleformation, or other formations with relatively thin hydrocarbon layers.Tar sands or thin oil shale formations may have thin shallow layers thatare more easily and uniformly heated using heaters placed insubstantially u-shaped wellbores. Substantially u-shaped wellbores mayalso be used to process formations with thick hydrocarbon layers. Insome embodiments, substantially u-shaped wellbores are used to accessrich layers in a thick hydrocarbon formation.

Heaters in substantially u-shaped wellbores may have long lengthscompared to heaters in vertical wellbores because horizontal heatingsections do not have problems with creep or hanging stress encounteredwith vertical heating elements. Substantially u-shaped wellbores maymake use of natural seals in the formation and/or the limited thicknessof the hydrocarbon layer. For example, the wellbores may be placed aboveor below natural seals in the formation without punching large numbersof holes in the natural seals, as would be needed with verticallyoriented wellbores. Using substantially u-shaped wellbores instead ofvertical wellbores may also reduce the number of wells needed to treat asurface footprint of the formation. Using less wells reduces capitalcosts for equipment and reduces the environmental impact of treating theformation by reducing the amount of wellbores on the surface and theamount of equipment on the surface. Substantially u-shaped wellbores mayalso utilize a lower ratio of overburden section to heated section thanvertical wellbores.

Substantially u-shaped wellbores may allow for flexible placement of theopenings of the wellbores on the surface. Openings to the wellbores maybe placed according to the surface topology of the formation. In certainembodiments, the openings of wellbores are placed at geographicallyaccessible locations such as topological highs (for examples, hills).For example, the wellbore may have a first opening on a first topologichigh and a second opening on a second topologic high and the wellborecrosses beneath a topologic low (for example, a valley with alluvialfill) between the first and second topologic highs. This placement ofthe openings may avoid placing openings or equipment in topologic lowsor other inaccessible locations. In addition, the water level may not beartesian in topologically high areas. Wellbores may be drilled so thatthe openings are not located near environmentally sensitive areas suchas, but not limited to, streams, nesting areas, or animal refuges.

FIG. 123 depicts a cross-sectional representation of an embodiment of aheater with an exposed metal heating element placed in a substantiallyu-shaped wellbore. Heaters 438A, 438B, 438C have first end portions atfirst location 664 on surface 568 of the formation and second endportions at second location 668 on the surface. Heaters 438A, 438B, 438Chave sections 682 in overburden 482. Sections 682 are configured toprovide little or no heat output. In certain embodiments, sections 682include an insulated electrical conductor such as insulated copper.Sections 682 are coupled to heating elements 644.

In certain embodiments, portions of heating elements 644 aresubstantially parallel in hydrocarbon layer 484. In certain embodiments,heating elements 644 are exposed metal heating elements. In certainembodiments, heating elements 644 are exposed metal temperature limitedheating elements. Heating elements 644 may include ferromagneticmaterials such as 9% by weight to 13% by weight chromium stainless steellike 410 stainless steel, chromium stainless steels such as T/P91 orT/P92, 409 stainless steel, VM12 (Vallourec and Mannesmann Tubes,France) or iron-cobalt alloys for use as temperature limited heaters. Insome embodiments, heating elements 644 are composite temperature limitedheating elements such as 410 stainless steel and copper compositeheating elements or 347H, iron, copper composite heating elements.Heating elements 644 may have lengths of at least about 100 m, at leastabout 500 m, or at least about 1000 m, up to lengths of about 6000 m.

Heating elements 644 may be solid rods or tubulars. In certainembodiments, solid rod heating elements have diameters several times theskin depth at the Curie temperature of the ferromagnetic material.Typically, the solid rod heating elements may have diameters of 1.91 cmor larger (for example, 2.5 cm, 3.2 cm, 3.81 cm, or 5.1 cm). In certainembodiments, tubular heating elements have wall thicknesses of at leasttwice the skin depth at the Curie temperature of the ferromagneticmaterial. Typically, the tubular heating elements have outside diametersof between about 2.5 cm and about 15.2 cm and wall thickness in rangebetween about 0.13 cm and about 1.01 cm.

In certain embodiments, tubular heating elements 644 allow fluids to beconvected through the tubular heating elements. Fluid flowing throughthe tubular heating elements may be used to preheat the tubular heatingelements to initially heat the formation and/or to recover heat from theformation after heating is completed for the in situ heat treatmentprocess. Fluids that may flow through the tubular heating elementsinclude, but are not limited to, air, water, steam, helium, carbondioxide or other fluids. In some embodiments, a hot fluid, such ascarbon dioxide or helium, flows through the tubular heating elements toprovide heat to the formation. The hot fluid may be used to provide heatto the formation before electrical heating is used to provide heat tothe formation. In some embodiments, the hot fluid is used to provideheat in addition to electrical heating. Using the hot fluid to provideheat to the formation in addition to providing electrical heating may beless expensive than using electrical heating alone to provide heat tothe formation. In some embodiments, water and/or steam flows through thetubular heating element to recover heat from the formation. The heatedwater and/or steam may be used for solution mining and/or otherprocesses.

Transition sections 684 may couple heating elements 644 to sections 682.In certain embodiments, transition sections 684 include material thathas a high electrical conductivity but is corrosion resistant, such as347 stainless steel over copper. In an embodiment, transition sectionsinclude a composite of stainless steel clad over copper. Transitionsections 684 inhibit overheating of copper and/or insulation in sections682.

FIG. 124 depicts a top view representation of an embodiment of a surfacepattern of the heaters depicted in FIG. 123. Heaters 438A-L may bearranged in a repeating triangular pattern on the surface of theformation. A triangle may be formed by heaters 438A, 438B, and 438C anda triangle formed by heaters 438C, 438D, and 438E. In some embodiments,heaters 438A-L are arranged in a straight line on the surface of theformation. Heaters 438A-L have first end portions at first location 664on the surface and second end portions at second location 668 on thesurface. Heaters 438A-L are arranged such that (a) the patterns at firstlocation 664 and second location 668 correspond to each other, (b) thespacing between heaters is maintained at the two locations on thesurface, and/or (c) the heaters all have substantially the same length(substantially the same horizontal distance between the end portions ofthe heaters on the surface as shown in the top view of FIG. 124).

As depicted in FIGS. 123 and 124, cables 686, 688 may be coupled totransformer 580 and one or more heater units, such as the heater unitincluding heaters 438A, 438B, 438C. Cables 686, 688 may carry a largeamount of power. In certain embodiments, cables 686, 688 are capable ofcarrying high currents with low losses. For example, cables 686, 688 maybe thick copper or aluminum conductors. The cables may also have thickinsulation layers. In some embodiments, cable 686 and/or cable 688 maybe superconducting cables. The superconducting cables may be cooled byliquid nitrogen. Superconducting cables are available from Superpower,Inc. (Schenectady, N.Y., U.S.A.). Superconducting cables may minimizepower loss and reduce the size of the cables needed to coupletransformer 580 to the heaters. In some embodiments, cables 686, 688 maybe made of carbon nanotubes. Carbon nanotubes as conductors may haveabout 1000 times the conductivity of copper for the same diameter. Also,carbon nanotubes may not require refrigeration during use.

In certain embodiments, bus bar 690A is coupled to first end portions ofheaters 438A-L and bus bar 690B is coupled to second end portions ofheaters 438A-L. Bus bars 690A,B electrically couple heaters 438A-L tocables 686, 688 and transformer 580. Bus bars 690A,B distribute power toheaters 438A-L. In certain embodiments, bus bars 690A,B are capable ofcarrying high currents with low losses. In some embodiments, bus bars690A,B are made of superconducting material such as the superconductormaterial used in cables 686, 688. In some embodiments, bus bars 690A,Bmay include carbon nanotube conductors.

As shown in FIG. 124, heaters 438A-L are coupled to a single transformer580. In certain embodiments, transformer 580 is a source of time-varyingcurrent. In certain embodiments, transformer 580 is an electricallyisolated, single-phase transformer. In certain embodiments, transformer580 provides power to heaters 438A-L from an isolated secondary phase ofthe transformer. First end portions of heaters 438A-L may be coupled toone side of transformer 580 while second end portions of the heaters arecoupled to the opposite side of the transformer. Transformer 580provides a substantially common voltage to the first end portions ofheaters 438A-L and a substantially common voltage to the second endportions of heaters 438A-L. In certain embodiments, transformer 580applies a voltage potential to the first end portions of heaters 438A-Lthat is opposite in polarity and substantially equal in magnitude to avoltage potential applied to the second end portions of the heaters. Forexample, a +660 V potential may be applied to the first end portions ofheaters 438A-L and a −660 V potential applied to the second end portionsof the heaters at a selected point on the wave of time-varying current(such as AC or modulated DC). Thus, the voltages at the two end portionof the heaters may be equal in magnitude and opposite in polarity withan average voltage that is substantially at ground potential.

Applying the same voltage potentials to the end portions of all heaters438A-L produces voltage potentials along the lengths of the heaters thatare substantially the same along the lengths of the heaters. FIG. 125depicts a cross-sectional representation, along a vertical plane, suchas the plane A-A shown in FIG. 123, of substantially u-shaped heaters ina hydrocarbon layer. The voltage potential at the cross-sectional pointshown in FIG. 125 along the length of heater 438A is substantially thesame as the voltage potential at the corresponding cross-sectionalpoints on heaters 438B-L. At lines equidistant between heater wellheads,the voltage potential is approximately zero. Other wells, such asproduction wells or monitoring wells, may be located along these zerovoltage potential lines, if desired. Production wells 206 located closeto the overburden may be used to transport formation fluid that isinitially in a vapor phase to the surface. Production wells locatedclose to a bottom of the heated portion of the formation may be used totransport formation fluid that is initially in a liquid phase to thesurface.

In certain embodiments, the voltage potential at the midpoint of heaters438A-L is about zero. Having similar voltage potentials along thelengths of heaters 438A-L inhibits current leakage between the heaters.Thus, there is little or no current flow in the formation and theheaters may have long lengths. Having the opposite polarity andsubstantially equal voltage potentials at the end portions of theheaters also halves the voltage applied at either end portion of theheater versus having one end portion of the heater grounded and one endportion at full potential. Reducing (halving) the voltage potentialapplied to an end portion of the heater generally reduces currentleakage, reduces insulator requirements, and/or reduces arcing distancesbecause of the lower voltage potential to ground applied at the endportions of the heaters.

In certain embodiments, substantially vertical heaters are used toprovide heat to the formation. Opposite polarity and substantially equalvoltage potentials, as described above, may be applied to the endportions of the substantially vertical heaters. FIG. 126 depicts a sideview representation of substantially vertical heaters coupled to asubstantially horizontal wellbore. Heaters 438A, 438B, 438C, 438D, 438E,438F are substantially vertical in hydrocarbon layer 484. First endportions of heaters 438A, 438B, 438C, 438D, 438E, 438F are coupled tobus bar 690A on a surface of the formation. Second end portions ofheaters 438A, 438B, 438C, 438D, 438E, 438F are coupled to bus bar 690Bin contacting section 656.

Bus bar 690B may be a bus bar located in a substantially horizontalwellbore in contacting section 656. Second end portions of heaters 438A,438B, 438C, 438D, 438E, 438F may be coupled to bus bar 690B by anymethod described herein or any method known in the art. For example,containers with thermite powder are coupled to bus bar 690B (forexample, by welding or brazing the containers to the bus bar), endportions of heaters 438A, 438B, 438C, 438D, 438E, 438F are placed insidethe containers, and the thermite powder is activated to electricallycouple the heaters to the bus bar. The containers may be coupled to busbar 690B by, for example, placing the containers in holes or recesses inbus bar 690B or coupled to the outside of the bus bar and then brazingor welding the containers to the bus bar.

Bus bar 690A and bus bar 690B may be coupled to transformer 580 withcables 686, 688, as described above. Transformer 580 may providevoltages to bar 690A and bus bar 690B as described above for theembodiments depicted in FIGS. 123 and 124. For example, transformer 580may apply a voltage potential to the first end portions of heaters438A-F that is opposite in polarity and substantially equal in magnitudeto a voltage potential applied to the second end portions of theheaters. Applying the same voltage potentials to the end portions of allheaters 438A-F may produce voltage potentials along the lengths of theheaters that are substantially the same along the lengths of theheaters. Applying the same voltage potentials to the end portions of allheaters 438A-F may inhibit current leakage between the heaters and/orinto the formation. In some embodiments, heaters 438A-F are electricallycoupled in pairs to the isolated delta winding on the secondary of athree-phase transformer.

In certain embodiments, it may be advantageous to allow some currentleakage into the formation during early stages of heating to heat theformation at a faster rate. Current leakage from the heaters into theformation electrically heats the formation directly. The formation isheated by direct electrical heating in addition to conductive heatprovided by the heaters. The formation (the hydrocarbon layer) may havean initial electrical resistance that averages at least 10 ohm m. Insome embodiments, the formation has an initial electrical resistance ofat least 100 ohm·m or of at least 300 ohm·m. Direct electrical heatingis achieved by having opposite potentials applied to adjacent heaters inthe hydrocarbon layer. Current may be allowed to leak into the formationuntil a selected temperature is reached in the heaters or in theformation. The selected temperature may be below or near the temperaturethat water proximate one or more heaters boils off. After water boilsoff, the hydrocarbon layer is substantially electrically isolated fromthe heaters and direct heating of the formation is inefficient. Afterthe selected temperature is reached, the voltage potential is applied inthe opposite polarity and substantially equal magnitude manner describedabove for FIGS. 123 and 124 so that adjacent heaters will have the samevoltage potential along their lengths.

Current is allowed to leak into the formation by reversing the polarityof one or more heaters shown in FIG. 124 so that a first group ofheaters has a positive voltage potential at first location 664 and asecond group of heaters has a negative voltage potential at the firstlocation. The first end portions, at first location 664, of a firstgroup of heaters (for example, heaters 438A, 438B, 438D, 438E, 438G,438H, 438J, 438K, depicted in FIG. 124) are applied with a positivevoltage potential that is substantially equal in magnitude to a negativevoltage potential applied to the second end portions, at second location668, of the first group of heaters. The first end portions, at firstlocation 664, of the second group of heaters (for example, heaters 438C,438F, 438I, 438L) are applied with a negative voltage potential that issubstantially equal in magnitude to the positive voltage potentialapplied to the first end portions of the first group of heaters.Similarly, the second end portions, at second location 668, of thesecond group of heaters are applied with a positive voltage potentialsubstantially equal in magnitude to the negative potential applied tothe second end portions of the first group of heaters. After theselected temperature is reached, the first end portions of both groupsof heaters are applied with voltage potential that is opposite inpolarity and substantially similar in magnitude to the voltage potentialapplied to the second end portions of both groups of heaters.

In some embodiments, the heating elements have thin electricallyinsulating material to inhibit current leakage from the heatingelements. In some embodiments, the thin electrically insulating layer isaluminum oxide or thermal spray coated aluminum oxide. In someembodiments, the thin electrically insulating layer is an enamel coatingof a ceramic composition. The thin electrically insulating layer mayinhibit heating elements of a three-phase heater from leaking currentbetween the elements, from leaking current into the formation, and fromleaking current to other heaters in the formation. Thus, the three-phaseheater may have a longer heater length.

In certain embodiments, a plurality of substantially horizontal (orinclined) heaters are coupled to a single substantially horizontal busbar in the subsurface formation. Having the plurality of substantiallyhorizontal heaters connected to a single bus bar in the subsurfacereduces the overall footprint of heaters on the surface of the formationand the number of wells drilled in the formation. In addition, theamount of subsurface space used to couple the heaters may be minimizedso that more of the formation is treated with heat to recoverhydrocarbons (for example, there is less unheated depth in theformation). The number and spacing of heaters coupled to the single busbar may be varied depending on factors such as, but not limited to, sizeof the treatment area, vertical thickness of the formation, heatingrequirements for the formation, number of layers in the formation, andcapacity limitations of the surface power supply.

FIG. 127 depicts an embodiment of pluralities of substantiallyhorizontal heaters 438A,B coupled to bus bars 690A,B in hydrocarbonlayer 484. Heaters 438A,B have sections 682 in the overburden ofhydrocarbon layer 484. Sections 682 may include high electricalconductivity, low thermal loss electrical conductors such as copper orcopper clad carbon steel. Heaters 438A,B enter hydrocarbon layer 484with substantially vertical sections and then redirect so that theheaters have substantially horizontal sections in hydrocarbon layer 484.The substantially horizontal sections of heaters 438A,B in hydrocarbonlayer 484 may provide the majority of the heat to the hydrocarbon layer.Heaters 438A,B may be coupled to bus bars 690A,B, which are locateddistant from each other in the formation while being substantiallyparallel to each other.

In certain embodiments, heaters 438A,B include exposed metal heatingelements. In certain embodiments, heaters 438A,B include exposed metaltemperature limited heating elements. The heating elements may includeferromagnetic materials such as 9% by weight to 13% by weight chromiumstainless steel like 410 stainless steel, chromium stainless steels suchas T/P91 or T/P92, 409 stainless steel, VM12 (Vallourec and MannesmannTubes, France) or iron-cobalt alloys for use as temperature limitedheaters. In some embodiments, the heating elements are compositetemperature limited heating elements such as 410 stainless steel andcopper composite heating elements or 347H, iron, copper compositeheating elements. The substantially horizontal sections of heaters438A,B in hydrocarbon layer 484 may have lengths of at least about 100m, at least about 500 m, or at least about 1000 m, up to lengths ofabout 6000 m.

In some embodiments, two groups of heaters 438A,B enter the subsurfacenear each other and then branch away from each other in hydrocarbonlayer 484. Having the surface portions of more than one group of heaterslocated near each other creates less of a surface footprint of theheaters and allows a single group of surface facilities to be used forboth groups of heaters.

In certain embodiments, the groups of heaters 438A or 438B are eachcoupled to a single transformer. In some embodiments, three heaters inthe groups are coupled in a triad configuration (each heater is coupledto one of the phases (A, B, or C) of a three phase transformer and thebus bar is coupled to the neutral, or center point, of the transformer).Each phase of the three-phase transformer may be coupled to more thanone heater in each group of heaters (for example, phase A may be coupledto 5 heaters in the group of heaters 438A). In some embodiments, theheaters are coupled to a single phase transformer (either in series orin parallel configurations).

FIG. 128 depicts an embodiment of pluralities of substantiallyhorizontal heaters 438A,B coupled to bus bars 690A,B in hydrocarbonlayer 484. In such an embodiment, two groups of heaters 438A,B enter theformation at distal locations on the surface of the formation. Heaters438A,B branch towards each other in hydrocarbon layer 484 so that theends of the heaters are directed towards each other. Heaters 438A,B maybe coupled to bus bars 690A,B, which are located proximate each otherand substantially parallel to each other. Bus bars 690A,B may enter thesubsurface in proximity to each other so that the footprint of the busbars on the surface is small.

In certain embodiments, heaters 438A,B are coupled to a single phasetransformer in series or parallel. The heaters may be coupled so thatthe polarity (direction of current flow) alternates in the row ofheaters so that each heater has a polarity opposite the heater adjacentto it. Additionally, heaters 438A,B and bus bars 690A,B may beelectrically coupled such that the bus bars are opposite in polarityfrom each other (the current flows in opposite directions at any pointin time in each bus bar). Coupling the heaters and the bus bars in sucha manner inhibits current leakage into and/or through the formation.

As shown in FIGS. 127 and 128, heaters 438A may be electrically coupledto bus bar 690A and heaters 438B may be electrically coupled to bus bar690B. Bus bars 690A,B may electrically couple to the ends of heaters438A,B and be a return or neutral connection for the heaters with busbar 690A being the neutral connection for heaters 438A and bus bar 690Bbeing the neutral connection for heaters 438B. Bus bars 690A,B may belocated in wellbores that are formed substantially perpendicular to thepath of wellbores with heaters 438A,B, as shown in FIG. 127. Directionaldrilling and/or magnetic steering may be used so that the wells for busbars 690A,B and the wellbores for heaters 438A,B intersect.

In certain embodiments, heaters 438A,B are coupled to bus bars 690A,Busing “mousetrap” type connectors 692. In some embodiments, othercouplings, such as those described herein or known in the art, are usedto couple heaters 438A,B to bus bars 690A,B. For example, a molten metalor a liquid conducting fluid may fill up the connection space (in thewellbores) to electrically couple the heaters and the bus bars.

FIG. 129 depicts an enlarged view of an embodiment of bus bar 690coupled to heaters 438 with connectors 692. In certain embodiments, busbar 690 includes carbon steel or other electrically conducting metals.In some embodiments, a high electrical conductivity conductor or metalis coupled to or included in bus bar 690. For example, bus bar 690 mayinclude carbon steel with copper cladded to the carbon steel.

In some embodiments, a centralizer or other centralizing device is usedto locate or guide heaters 438 and/or bus bars 690 so that the heatersand bus bars can be coupled. FIG. 130 depicts an enlarged view of anembodiment of bus bar 690 coupled to heater 438 with connectors 692 andcentralizers 558. Centralizers 558 may locate heater 438 and/or bus bar690 so that connectors 692 easily couple the heater and the bus bar.Centralizers 558 may ensure proper spacing of heater 438 and/or bus bar690 so that the heater and the bus bar can be coupled with connectors692. Centralizers 558 may inhibit heater 438 and/or bus bar 690 fromcontacting the sides of the wellbores at or near connectors 692.

FIG. 131 depicts a cross-sectional representation of connector 692coupling to bus bar 690. FIG. 132 depicts a perspective representationof connector 692 coupling to bus bar 690. Connectors 692 are shown inproximity to bus bar 690 (before the connector clamps around the busbar). Connector 692 is connected or directly attached to the heater sothat the connector is rotatable around the end of the heater whilemaintaining electrical contact with the heater. In some embodiments, theconnector and the end of the heater are twisted into position to alignwith the bus bar. Connector 692 includes collets 694. Collets 694 areshaped (for example, diagonally cut or helically profiled) so that asthe connector is pushed onto bus bar 690, the shape of the colletsrotates the head of the connector as the collets slide over the bus bar.Collets 694 may be spring loaded so that the collets hold down againstbus bar 690 after the collets slide over the bus bar. Thus, connector692 clamps to bus bar 690 using collets 694. Connector 692, includingcollets 694, is made of electrically conductive materials so that theconnector electrically couples bus bar 690 to the heater attached to theconnector.

In some embodiments, an explosive element is added to connectors 692,such as the connectors shown in FIGS. 131 and 132. Connector 692 is usedto position bus bar 690 and the heater in proper positions for explosivebonding of the bus bar to the heater. The explosive element may belocated on connector 692. For example, the explosive element may belocated on one or both of collets 694. The explosive element may be usedto explosively bond connector 692 to bus bar 690 so that the heater ismetallically bonded to the bus bar.

In some embodiment, the explosive bonding is applied along the axialdirection of bus bar 690. In some embodiments, the explosive bondingprocess is a self cleaning process. For example, the explosive bondingprocess may drive out air and/or debris from between components duringthe explosion. In some embodiments, the explosive element is a shapecharge explosive element. Using the shape charge element may focus theexplosive energy in a desired direction.

FIG. 133 depicts an embodiment of three u-shaped heaters with commonoverburden sections coupled to a single three-phase transformer. Incertain embodiments, heaters 438A, 438B, 438C are exposed metal heaters.In some embodiments, heaters 438A, 438B, 438C are exposed metal heaterswith a thin, electrically insulating coating on the heaters. Forexample, heaters 438A, 438B, 438C may be 410 stainless steel, carbonsteel, 347H stainless steel, or other corrosion resistant stainlesssteel rods or tubulars (such as 2.5 cm or 3.2 cm diameter rods). Therods or tubulars may have porcelain enamel coatings on the exterior ofthe rods to electrically insulate the rods.

In some embodiments, heaters 438A, 438B, 438C are insulated conductorheaters. In some embodiments, heaters 438A, 438B, 438C areconductor-in-conduit heaters. Heaters 438A, 438B, 438C may havesubstantially parallel heating sections in hydrocarbon layer 484.Heaters 438A, 438B, 438C may be substantially horizontal or at anincline in hydrocarbon layer 484. In some embodiments, heaters 438A,438B, 438C enter the formation through common wellbore 428A. Heaters438A, 438B, 438C may exit the formation through common wellbore 428B. Incertain embodiments, wellbores 428A, 428B are uncased (for example, openwellbores) in hydrocarbon layer 484.

Openings 556A, 556B, 556C span between wellbore 428A and wellbore 428B.Openings 556A, 556B, 556C may be uncased openings in hydrocarbon layer484. In certain embodiments, openings 556A, 556B, 556C are formed bydrilling from wellbore 428A and/or wellbore 428B. In some embodiments,openings 556A, 556B, 556C are formed by drilling from each wellbore 428Aand 428B and connecting at or near the middle of the openings. Drillingfrom both sides towards the middle of hydrocarbon layer 484 allowslonger openings to be formed in the hydrocarbon layer. Thus, longerheaters may be installed in hydrocarbon layer 484. For example, heaters438A, 438B, 438C may have lengths of at least about 1500 m, at leastabout 3000 m, or at least about 4500 m.

Having multiple long, substantially horizontal or inclined heatersextending from only two wellbores in hydrocarbon layer 484 reduces thefootprint of wells on the surface needed for heating the formation. Thenumber of overburden wellbores that need to be drilled in the formationis reduced, which reduces capital costs per heater in the formation.Heating the formation with long, substantially horizontal or inclinedheaters also reduces overall heat losses in overburden 482 when heatingthe formation because of the reduced number of overburden sections usedto treat the formation (for example, losses in overburden 482 are asmaller fraction of total power supplied to the formation).

In some embodiments, heaters 438A, 438B, 438C are installed in wellbores428A, 428B and openings 556A, 556B, 556C by pulling the heaters throughthe wellbores and the openings from one end to the other. For example,an installation tool may be pushed through the openings and coupled to aheater in wellbore 428A. The heater may then be pulled through theopenings towards wellbore 428B using the installation tool. The heatermay be coupled to the installation tool using a connector such as aclaw, a catcher, or other devices known in the art.

In some embodiments, the first half of an opening is drilled fromwellbore 428A and then the second half of the opening is drilled fromwellbore 428B through the first half of the opening. The drill bit maybe pushed through to wellbore 428A and a first heater may be coupled tothe drill bit to pull the first heater back through the opening andinstall the first heater in the opening. The first heater may be coupledto the drill bit using a connector such as a claw, a catcher, or otherdevices known in the art.

After the first heater is installed, a tube or other guide may be placedin wellbore 428A and/or wellbore 428B to guide drilling of a secondopening. FIG. 134 depicts a top view of an embodiment of heater 438A anddrilling guide 696 in wellbore 428. Drilling guide 696 may be used toguide the drilling of the second opening in the formation and theinstallation of a second heater in the second opening. Insulator 534Amay electrically and mechanically insulate heater 438A from drillingguide 696. Drilling guide 696 and insulator 534A may protect heater 438Afrom being damaged while the second opening is being drilled and thesecond heater is being installed.

After the second heater is installed, drilling guide 696 may be placedin wellbore 428 to guide drilling of a third opening, as shown in FIG.135. Drilling guide 696 may be used to guide the drilling of the thirdopening in the formation and the installation of a third heater in thethird opening. Insulators 534A and 534B may electrically andmechanically insulate heaters 438A and 438B, respectively, from drillingguide 696. Drilling guide 696 and insulators 534A and 534B may protectheaters 438A and 438B from being damaged while the third opening isbeing drilled and the third heater is being installed. After the thirdheater is installed, insulators 534A and 534B may be removed and acentralizer may be placed in wellbore 428 to separate and space heaters438A, 438B, 438C. FIG. 136 depicts heaters 438A, 438B, 438C in wellbore428 separated by centralizer 558.

In some embodiments, all the openings are formed in the formation andthen the heaters are installed in the formation. In certain embodiments,one of the openings is formed and one of the heaters is installed in theformation before the other openings are formed and the other heaters areinstalled. The first installed heater may be used as a guide during theformation of additional openings. The first installed heater may beenergized to produce an electromagnetic field that is used to guide theformation of the other openings. For example, the first installed heatermay be energized with a bipolar DC current to magnetically guidedrilling of the other openings.

In certain embodiments, heaters 438A, 438B, 438C are coupled to a singlethree-phase transformer 580 at one end of the heaters, as shown in FIG.133. Heaters 438A, 438B, 438C may be electrically coupled in a triadconfiguration. In some embodiments, two heaters are coupled together ina diad configuration. Transformer 580 may be a three-phase wyetransformer. The heaters may each be coupled to one phase of transformer580. Using three-phase power to power the heaters may be more efficientthan using single-phase power. Using three-phase connections for theheaters allows the magnetic fields of the heaters in wellbore 428A tocancel each other. The cancelled magnetic fields may allow overburdencasing 564A to be ferromagnetic (for example, carbon steel). Usingferromagnetic casings in the wellbores may be less expensive and/oreasier to install than non-ferromagnetic casings (such as fiberglasscasings).

In some embodiments, the overburden section of heaters 438A, 438B, 438Care coated with an insulator, such as a polymer or an enamel coating, toinhibit shorting between the overburden sections of the heaters. In someembodiments, only the overburden sections of the heaters in wellbore428A are coated with the insulator as the heater sections in wellbore428B may not have significant electrical losses. In some embodiments,ends or end portions (portions at, near, or in the vicinity of the ends)of heaters 438A, 438B, 438C in wellbore 428A are at least one diameterof the heaters away from overburden casing 564A so that no insulator isneeded. The ends or end portions of heaters 438A, 438B, 438C may be, forexample, centralized in wellbore 428A using a centralizer to keep theheaters the desired distance away from overburden casing 564A.

In some embodiments, the ends or end portions of heaters 438A, 438B,438C passing through wellbore 428B are electrically coupled together andgrounded outside of the wellbore, as shown in FIG. 133. The magneticfields of the heaters may cancel each other in wellbore 428B. Thus,overburden casing 564B may be ferromagnetic (for example, carbon steel).In certain embodiments, the overburden section of heaters 438A, 438B,438C are copper rods or tubulars. The build sections of the heaters (thetransition sections between the overburden sections and the heatingsections) may also be made of copper or similar electrically conductivematerial.

In some embodiments, the ends or end portions of heaters 438A, 438B,438C passing through wellbore 428B are electrically coupled togetherinside the wellbore. The ends or end portions of the heaters may becoupled inside the wellbore at or near the bottom of overburden 482.Coupling the heaters together at or near overburden 482 reduceselectrical losses in the overburden section of the wellbore.

FIG. 137 depicts an embodiment for coupling ends or end portions ofheaters 438A, 438B, 438C in wellbore 428B. Plate 698 may be located ator near the bottom of the overburden section of wellbore 428B. Plate 698may have openings sized to allow heaters 438A, 438B, 438C to be insertedthrough the plate. Plate 698 may be slid down heaters 438A, 438B, 438Cinto position in wellbore 428B. Plate 698 may be made of copper oranother electrically conductive material.

Balls 700 may be placed into the overburden section of wellbore 428B.Plate 698 may allow balls 700 to settle in the overburden section ofwellbore 428B around heaters 438A, 438B, 438C. Balls 700 may be made ofelectrically conductive material such as copper or nickel-plated copper.Balls 700 and plate 698 may electrically couple heaters 438A, 438B, 438Cto each other so that the heaters are grounded. In some embodiments,portions of the heaters above plate 698 (the overburden sections of theheaters) are made of carbon steel while portions of the heaters belowthe plate (build sections of the heaters) are made of copper.

In some embodiments, heaters 438A, 438B, 438C, as depicted in FIG. 133,provide varying heat outputs along the lengths of the heaters. Forexample, heaters 438A, 438B, 438C may have varying dimensions (forexample, thicknesses or diameters) along the lengths of the heater. Thevarying thicknesses may provide different electrical resistances alongthe length of the heater and, thus, different heat outputs along thelength of the heaters.

In some embodiments, heaters 438A, 438B, 438C are divided into two ormore sections of heating. In some embodiments, the heaters are dividedinto repeating sections of different heat outputs (for example,alternating sections of two different heat outputs that are repeated).In some embodiments, the repeating sections of different heat outputsmay be used to heat the formation in stages. In one embodiment, thehalves of the heaters closest to wellbore 428A may provide heat in afirst section of hydrocarbon layer 484 and the halves of the heatersclosest to wellbore 428B may provide heat in a second section ofhydrocarbon layer 484. Hydrocarbons in the formation may be mobilized bythe heat provided in the first section. Hydrocarbons in the secondsection may be heated to higher temperatures than the first section toupgrade the hydrocarbons in the second section (for example, thehydrocarbons may be further mobilized and/or pyrolyzed). Hydrocarbonsfrom the first section may move, or be moved, into the second sectionfor the upgrading. For example, a drive fluid may be provided throughwellbore 428A to move the first section mobilized hydrocarbons to thesecond section.

In some embodiments, more than three heaters extend from wellbore 428Aand/or 428B. If multiples of three heaters extend from the wellbores andare coupled to transformer 580, the magnetic fields may cancel in theoverburden sections of the wellbores as in the case of three heaters inthe wellbores. For example, six heaters may be coupled to transformer580 with two heaters coupled to each phase of the transformer to cancelthe magnetic fields in the wellbores.

In some embodiments, multiple heaters extend from one wellbore indifferent directions. FIG. 138 depicts a schematic of an embodiment ofmultiple heaters extending in different directions from wellbore 428A.Heaters 438A, 438B, 438C may extend to wellbore 428B. Heaters 438D,438E, 438F may extend to wellbore 428C in the opposite direction ofheaters 438A, 438B, 438C. Heaters 438A, 438B, 438C and heaters 438D,438E, 438F may be coupled to a single, three-phase transformer so thatmagnetic fields are cancelled in wellbore 428A.

In some embodiments, heaters 438A, 438B, 438C may have different heatoutputs from heaters 438D, 438E, 438F so that hydrocarbon layer 484 isdivided into two heating sections with different heating rates and/ortemperatures (for example, a mobilization and a pyrolyzation section).In some embodiments, heaters 438A, 438B, 438C and/or heaters 438D, 438E,438F may have heat outputs that vary along the lengths of the heaters tofurther divide hydrocarbon layer 484 into more heating sections. In someembodiments, additional heaters may extend from wellbore 428B and/orwellbore 428C to other wellbores in the formation as shown by the dashedlines in FIG. 138.

In some embodiments, multiple levels of heaters extend between twowellbores. FIG. 139 depicts a schematic of an embodiment of multiplelevels of heaters extending between wellbore 428A and wellbore 428B.Heaters 438A, 438B, 438C may provide heat to a first level ofhydrocarbon layer 484. Heaters 438D, 438E, 438F may branch off andprovide heat to a second level of hydrocarbon layer 484. Heaters 438G,438H, 438I may further branch off and provide heat to a third level ofhydrocarbon layer 484. In some embodiments, heaters 438A, 438B, 438C,heaters 438D, 438E, 438F, and heaters 438G, 438H, 438I provide heat tolevels in the formation with different properties. For example, thedifferent groups of heaters may provide different heat outputs to levelswith different properties in the formation so that the levels are heatedat or about the same rate.

In some embodiments, the levels are heated at different rates to createdifferent heating zones in the formation. For example, the first level(heated by heaters 438A, 438B, 438C) may be heated so that hydrocarbonsare mobilized, the second level (heated by heaters 438D, 438E, 438F) maybe heated so that hydrocarbons are somewhat upgraded from the firstlevel, and the third level (heated by heaters 438G, 438H, 438I) may beheated to pyrolyze hydrocarbons. As another example, the first level maybe heated to create gases and/or drive fluid in the first level andeither the second level or the third level may be heated to mobilizeand/or pyrolyze fluids or just to a level to allow production in thelevel. In addition, heaters 438A, 438B, 438C, heaters 438D, 438E, 438F,and/or heaters 438G, 438H, 438I may have heat outputs that vary alongthe lengths of the heaters to further divide hydrocarbon layer 484 intomore heating sections.

FIG. 140 depicts a schematic of an embodiment of a u-shaped heater thathas an inductively energized tubular. Heater 438 includes electricalconductor 572 and tubular 702 in an opening that spans between wellbore428A and wellbore 428B. In certain embodiments, electrical conductor 572and/or the current carrying portion of the electrical conductor iselectrically insulated from tubular 702. Electrical conductor 572 and/orthe current carrying portion of the electrical conductor is electricallyinsulated from tubular 702 such that electrical current does not flowfrom the electrical conductor to the tubular, or vice versa (forexample, the tubular is not directly connected electrically to theelectrical conductor).

In some embodiments, electrical conductor 572 is centralized insidetubular 702 (for example, using centralizers 558 or other supportstructures, as shown in FIG. 141). Centralizers 558 may electricallyinsulate electrical conductor 572 from tubular 702. In some embodiments,tubular 702 contacts electrical conductor 572. For example, tubular 702may hang, drape, or otherwise touch electrical conductor 572. In someembodiments, electrical conductor 572 includes electrical insulation(for example, magnesium oxide or porcelain enamel) that insulates thecurrent carrying portion of the electrical conductor from tubular 702.The electrical insulation inhibits current from flowing between thecurrent carrying portion of electrical conductor 572 and tubular 702 ifthe electrical conductor and the tubular are in physical contact witheach other.

In some embodiments, electrical conductor 572 is an exposed metalconductor heater or a conductor-in-conduit heater. In certainembodiments, electrical conductor 572 is an insulated conductor such asa mineral insulated conductor. The insulated conductor may have a coppercore, copper alloy core, or a similar electrically conductive, lowresistance core that has low electrical losses. In some embodiments, thecore is a copper core with a diameter between about 0.5″ (1.27 cm) andabout 1″ (2.54 cm). The sheath or jacket of the insulated conductor maybe a non-ferromagnetic, corrosion resistant steel such as 347 stainlesssteel, 625 stainless steel, 825 stainless steel, 304 stainless steel, orcopper with a protective layer (for example, a protective cladding). Thesheath may have an outer diameter of between about 1″ (2.54 cm) andabout 1.25″ (3.18 cm).

In some embodiments, the sheath or jacket of the insulated conductor isin physical contact with the tubular 702 (for example, the tubular is inphysical contact with the sheath along the length of the tubular) or thesheath is electrically connected to the tubular. In such embodiments,the electrical insulation of the insulated conductor electricallyinsulates the core of the insulated conductor from the jacket and thetubular. FIG. 142 depicts an embodiment of an induction heater with thesheath of an insulated conductor in electrical contact with tubular 702.Electrical conductor 572 is the insulated conductor. The sheath of theinsulated conductor is electrically connected to tubular 702 usingelectrical contactors 704. In some embodiments, electrical contactors704 are sliding contactors. In certain embodiments, electricalcontactors 704 electrically connect the sheath of the insulatedconductor to tubular 702 at or near the ends of the tubular.Electrically connecting at or near the ends of tubular 702 substantiallyequalizes the voltage along the tubular with the voltage along thesheath of the insulated conductor. Equalizing the voltages along tubular702 and along the sheath may inhibit arcing between the tubular and thesheath.

Tubular 702, such as the tubular shown in FIGS. 140, 141, and 142, maybe ferromagnetic or include ferromagnetic materials. Tubular 702 mayhave a thickness such that when electrical conductor 572 induceselectrical current flow on the surfaces of tubular 702 when theelectrical conductor is energized with time-varying current. Theelectrical conductor induces electrical current flow due to theferromagnetic properties of the tubular. Current flow is induced on boththe inside surface of the tubular and the outside surface of tubular702. Tubular 702 may operate as a skin effect heater when current flowis induced in the skin depth of one or more of the tubular surfaces. Incertain embodiments, the induced current circulates axially(longitudinally) on the inside and/or outside surfaces of tubular 702.Longitudinal flow of current through electrical conductor 572 inducesprimarily longitudinal current flow in tubular 702 (the majority of theinduced current flow is in the longitudinal direction in the tubular).Having primarily longitudinal induced current flow in tubular 702 mayprovide a higher resistance per foot than if the induced current flow isprimarily angular current flow.

In certain embodiments, current flow in tubular 702 is induced with lowfrequency current in electrical conductor 572 (for example, from 50 Hzor 60 Hz up to about 1000 Hz). In some embodiments, induced currents onthe inside and outside surfaces of tubular 702 are substantially equal.

In certain embodiments, tubular 702 has a thickness that is greater thanthe skin depth of the ferromagnetic material in the tubular at or nearthe Curie temperature of the ferromagnetic material or at or near thephase transformation temperature of the ferromagnetic material. Forexample, tubular 702 may have a thickness of at least 2.1, at least 2.5times, at least 3 times, or at least 4 times the skin depth of theferromagnetic material in the tubular near the Curie temperature or thephase transformation temperature of the ferromagnetic material. Incertain embodiments, tubular 702 has a thickness of at least 2.1 times,at least 2.5 times, at least 3 times, or at least 4 times the skin depthof the ferromagnetic material in the tubular at about 50° C. below theCurie temperature or the phase transformation temperature of theferromagnetic material.

In certain embodiments, tubular 702 is carbon steel. In someembodiments, tubular 702 is coated with a corrosion resistant coating(for example, porcelain or ceramic coating) and/or an electricallyinsulating coating. In some embodiments, electrical conductor 572 has anelectrically insulating coating. Examples of the electrically insulatingcoating on tubular 702 and/or electrical conductor 572 include, but arenot limited to, a porcelain enamel coating, an alumina coating, or analumina-titania coating.

In some embodiments, tubular 702 and/or electrical conductor 572 arecoated with a coating such as polyethylene or another suitable lowfriction coefficient coating that may melt or decompose when the heateris energized. The coating may facilitate placement of the tubular and/orthe electrical conductor in the formation.

In some embodiments, tubular 702 includes corrosion resistantferromagnetic material such as, but not limited to, 410 stainless steel,446 stainless steel, T/P91 stainless steel, T/P92 stainless steel, alloy52, alloy 42, and Invar 36. In some embodiments, tubular 702 is astainless steel tubular with cobalt added (for example, between about 3%by weight and about 10% by weight cobalt added) and/or molybdenum (forexample, about 0.5% molybdenum by weight).

At or near the Curie temperature or the phase transformation temperatureof the ferromagnetic material in tubular 702, the magnetic permeabilityof the ferromagnetic material decreases rapidly. When the magneticpermeability of tubular 702 decreases at or near the Curie temperatureor the phase transformation temperature, there is little or no currentflow in the tubular because, at these temperatures, the tubular isessentially non-ferromagnetic and electrical conductor 572 is unable toinduce current flow in the tubular. With little or no current flow intubular 702, the temperature of the tubular will drop to lowertemperatures until the magnetic permeability increases and the tubularbecomes ferromagnetic. Thus, tubular 702 self-limits at or near theCurie temperature or the phase transformation temperature and operatesas a temperature limited heater due to the ferromagnetic properties ofthe ferromagnetic material in the tubular. Because current is induced intubular 702, the turndown ratio may be higher and the drop in currentsharper for the tubular than for temperature limited heaters that applycurrent directly to the ferromagnetic material. For example, heaterswith current induced in tubular 702 may have turndown ratios of at leastabout 5, at least about 10, or at least about 20 while temperaturelimited heaters that apply current directly to the ferromagneticmaterial may have turndown ratios that are at most about 5.

When current is induced in tubular 702, the tubular provides heat tohydrocarbon layer 484 and defines the heating zone in the hydrocarbonlayer. In certain embodiments, tubular 702 heats to temperatures of atleast about 300° C., at least about 500° C., or at least about 700° C.Because current is induced on both the inside and outside surfaces oftubular 702, the heat generation of the tubular is increased as comparedto temperature limited heaters that have current directly applied to theferromagnetic material and current flow is limited to one surface. Thus,less current may be provided to electrical conductor 572 to generate thesame heat as heaters that apply current directly to the ferromagneticmaterial. Using less current in electrical conductor 572 decreases powerconsumption and reduces power losses in the overburden of the formation.

In certain embodiments, tubulars 702 have large diameters. The largediameters may be used to equalize or substantially equalize highpressures on the tubular from either the inside or the outside of thetubular. In some embodiments, tubular 702 has a diameter in a rangebetween about 1.5″ (about 3.8 cm) and about 6″ (about 15.2 cm). In someembodiments, tubular 702 has a diameter in a range between about 3 cmand about 13 cm, between about 4 cm and about 12 cm, or between about 5cm and about 11 cm. Increasing the diameter of tubular 702 may providemore heat output to the formation by increasing the heat transfersurface area of the tubular.

In certain embodiments, tubular 702 has surfaces that are shaped toincrease the resistance of the tubular. FIG. 143 depicts an embodimentof a heater with tubular 702 having radial grooved surfaces. Heater 438may include electrical conductors 572A,B coupled to tubular 702.Electrical conductors 572A,B may be insulated conductors. Electricalcontactors may electrically and physically couple electrical conductors572A,B to tubular 702. In certain embodiments, the electrical contactorsare attached to ends of electrical conductors 572A,B. The electricalcontactors have a shape such that when the ends of electrical conductors572A,B are pushed into the ends of tubular 702, the electricalcontactors physically and electrically couple the electrical conductorsto the tubular. For example, the electrical contactors may be coneshaped. Heater 438 generates heat when current is applied directly totubular 702. Current is provided to tubular 702 using electricalconductors 572A,B. Grooves 706 may increase the heat transfer surfacearea of tubular 702.

In some embodiments, one or more surfaces of the tubular of an inductionheater may be textured to increase the resistance of the heater andincrease the heat transfer surface area of the tubular. FIG. 144 depictsheater 438 that is an induction heater. Electrical conductor 572 extendsthrough tubular 702.

Tubular 702 may include grooves 706. In some embodiments, grooves 706are cut in tubular 702. In some embodiments, fins are coupled to tubularto form ridges and grooves 706. The fins may be welded or otherwiseattached to the tubular. In an embodiment, the fins are coupled to atubular sheath that is placed over the tubular. The sheath is physicallyand electrically coupled to the tubular to form tubular 702.

In certain embodiments, grooves 706 are on the outer surface of tubular702. In some embodiments, the grooves are on the inner surface of thetubular. In some embodiments, the grooves are on both the inner andouter surfaces of the tubular.

In certain embodiments, grooves 706 are radial grooves (grooves thatwrap around the circumference of tubular 702). In certain embodiments,grooves 706 are straight, angled, or spiral grooves or protrusions. Insome embodiments, grooves 706 are evenly spaced grooves along thesurface of tubular 702. In some embodiments, grooves 706 are part of athreaded surface on tubular 702 (the grooves are formed as a windingthread on the surface). Grooves 706 may have a variety of shapes asdesired. For example, grooves 706 may have square edges, rectangularedges, v-shaped edges, u-shaped edges, or have rounded edges.

Grooves 706 increase the effective resistance of tubular 702 byincreasing the path length of induced current on the surface of thetubular. Grooves 706 increase the effective resistance of tubular 702 ascompared to a tubular with the same inside and outside diameters withsmooth surfaces. Because induced current travels axially, the inducedcurrent has to travel up and down the grooves along the surface of thetubular. Thus, the depth of grooves 706 may be varied to provide aselected resistance in tubular 702. For example, increasing the groovesdepth increases the path length and the resistance.

Increasing the resistance of tubular 702 with grooves 706 increases theheat generation of the tubular as compared to a tubular with smoothsurfaces. Thus, the same electrical current in electrical conductor 572will provide more heat output in the radial grooved surface tubular thanthe smooth surface tubular. Therefore, to provide the same heat outputwith the radial grooved surface tubular as the smooth surface tubular,less current is needed in electrical conductor 572 with the radialgrooved surface tubular.

In some embodiments, grooves 706 are filled with materials thatdecompose at lower temperatures to protect the grooves duringinstallation of tubular 702. For example, grooves 706 may be filled withpolyethylene or asphalt. The polyethylene or asphalt may melt and/ordesorb when heater 438 reaches normal operating temperatures of theheater.

It is to be understood that grooves 706 may be used in other embodimentsof tubulars 702 described herein to increase the resistance of suchtubulars. For example, grooves 706 may be used in embodiments oftubulars 702 depicted in FIGS. 140, 141, and 142.

FIG. 145 depicts an embodiment of heater 438 divided into tubularsections to provide varying heat outputs along the length of the heater.Heater 438 may include tubular sections 702A, 702B, 702C, 702D that havedifferent properties to provide different heat outputs in each tubularsection. Heat output from tubular sections 702D may be less than theheat output from grooved sections 702A, 702B, 702C. Examples ofproperties that may be varied include, but are not limited to,thicknesses, diameters, cross-sectional areas, resistances, materials,number of grooves, depth of grooves. The different properties in tubularsections 702A, 702B, and 702C may provide different maximum operatingtemperatures (for example, different Curie temperatures or phasetransformation temperatures) along the length of heater 438. Thedifferent maximum temperatures of the tubular sections providesdifferent heat outputs from the tubular sections. Sections such asgrooved section 702A may be separate sections that are placed down thewellbore in separation installation procedures. Some sections, such asgrooved section 702B and 702C may be connected together by non-groovedsection 702D, and may be placed down the wellbore together.

Providing different heat outputs along heater 438 may provide differentheating in one or more hydrocarbon layers. For example, heater 438 maybe divided into two or more sections of heating to provide differentheat outputs to different sections of a hydrocarbon layer and/ordifferent hydrocarbon layers.

In one embodiment, a first portion of heater 438 may provide heat to afirst section of the hydrocarbon layer and a second portion of theheater may provide heat to a second section of the hydrocarbon layer.Hydrocarbons in the first section may be mobilized by the heat providedby the first portion of the heater. Hydrocarbons in the second sectionmay be heated by the second portion of the heater to a highertemperature than the first section. The higher temperature in the secondsection may upgrade hydrocarbons in the second section relative to thefirst section. For example, the hydrocarbons may be mobilized,visbroken, and/or pyrolyzed in the second section. Hydrocarbons from thefirst section may be moved into the second section by, for example, adrive fluid provided to the first section. As another example, heater438 may have end sections that provide higher heat outputs to counteractheat losses at the ends of the heater to maintain a more constanttemperature in the heated portion of the formation.

In certain embodiments, three, or multiples of three, electricalconductors enter and exit the formation through common wellbores withtubulars surrounding the electrical conductors in the portion of theformation to be heated. FIG. 146 depicts an embodiment of threeelectrical conductors 572A,B,C entering the formation through firstcommon wellbore 428A and exiting the formation through second commonwellbore 428C with three tubulars 702A,B,C surrounding the electricalconductors in hydrocarbon layer 484. In some embodiments, electricalconductors 572A,B,C are powered by a single, three-phase wyetransformer. Tubulars 702A,B,C and portions of electrical conductors572A,B,C may be in three separate wellbores in hydrocarbon layer 484.The three separate wellbores may be formed by drilling the wellboresfrom first common wellbore 428A to second common wellbore 428B, viceversa, or drilling from both common wellbores and connecting the drilledopenings in the hydrocarbon layer.

Having multiple induction heaters extending from only two wellbores inhydrocarbon layer 484 reduces the footprint of wells on the surfaceneeded for heating the formation. The number of overburden wellboresdrilled in the formation is reduced, which reduces capital costs perheater in the formation. Power losses in the overburden may be a smallerfraction of total power supplied to the formation because of the reducednumber of wells through the overburden used to treat the formation. Inaddition, power losses in the overburden may be smaller because thethree phases in the common wellbores substantially cancel each other andinhibit induced currents in the casings or other structures of thewellbores.

In some embodiments, three, or multiples of three, electrical conductorsand tubulars are located in separate wellbores in the formation. FIG.147 depicts an embodiment of three electrical conductors 572A,B,C andthree tubulars 702A,B,C in separate wellbores in the formation.Electrical conductors 572A,B,C may be powered by single, three-phase wyetransformer 580 with each electrical conductor coupled to one phase ofthe transformer. In some embodiments, the single, three-phase wyetransformer is used to power 6, 9, 12, or other multiples of threeelectrical conductors. Connecting multiples of three electricalconductors to the single, three-phase wye transformer may reduceequipment costs for providing power to the induction heaters.

In some embodiments, two, or multiples of two, electrical conductorsenter the formation from a first common wellbore and exit the formationfrom a second common wellbore with tubulars surrounding each electricalconductor in the hydrocarbon layer. The multiples of two electricalconductors may be powered by a single, two-phase transformer. In suchembodiments, the electrical conductors may be homogenous electricalconductors (for example, insulated conductors using the same materialsthroughout) in the overburden sections and heating sections of theinsulated conductor. The reverse flow of current in the overburdensections may reduce power losses in the overburden sections of thewellbores because the currents reduce or cancel inductive effects in theoverburden sections.

In certain embodiments, tubulars 702 depicted in FIGS. 140-146 includemultiple layers of ferromagnetic materials separated by electricalinsulators. FIG. 148 depicts an embodiment of a multilayered inductiontubular. Tubular 702 includes ferromagnetic layers 708A,B,C separated byelectrical insulators 534A,B. Three ferromagnetic layers and two layersof electrical insulators are shown in FIG. 148. Tubular 702 may includeadditional ferromagnetic layers and/or electrical insulators as desired.For example, the number of layers may be chosen to provide a desiredheat output from the tubular.

Ferromagnetic layers 708A,B,C are electrically insulated from electricalconductor 572 by, for example, an air gap. Ferromagnetic layers 708A,B,Care electrically insulated from each other by electrical insulator 534Aand electrical insulator 534B. Thus, direct flow of current is inhibitedbetween ferromagnetic layers 708A,B,C and electrical conductor 572. Whencurrent is applied to electrical conductor 572, electrical current flowis induced in ferromagnetic layers 708A,B,C because of the ferromagneticproperties of the layers. Having two or more electrically insulatedferromagnetic layers provides multiple current induction loops for theinduced current. The multiple current induction loops may effectivelyappear as electrical loads in series to a power source for electricalconductor 572. The multiple current induction loops may increase theheat generation per unit length of tubular 702 as compared to a tubularwith only one current induction loop. For the same heat output, thetubular with multiple layers may have a higher voltage and lower currentas compared to the single layer tubular.

In certain embodiments, ferromagnetic layers 708A,B,C include the sameferromagnetic material. In some embodiments, ferromagnetic layers708A,B,C include different ferromagnetic materials. Properties offerromagnetic layers 708A,B,C may be varied to provide different heatoutputs from the different layers. Examples of properties offerromagnetic layers 708A,B,C that may be varied include, but are notlimited to, ferromagnetic material and thicknesses of the layers.

Electrical insulators 534A and 534B may be magnesium oxide, porcelainenamel, and/or another suitable electrical insulator. The thicknessesand/or materials of electrical insulators 534A and 534B may be varied toprovide different operating parameters for tubular 702.

In some embodiments, fluids are circulated through tubulars 702 depictedin FIGS. 140-146. In some embodiments, fluids are circulated through thetubulars to add heat to the formation. For example, fluids may becirculated through the tubulars to preheat the formation prior toenergizing the tubulars (providing current to the heating system). Insome embodiments, fluids are circulated through the tubulars to recoverheat from the formation. The recovered heat may be used to provide heatto other portions of the formation and/or surface processes used totreat fluids produced from the formation. In some embodiments, thefluids are used to cool down the heater.

In certain embodiments, insulated conductors are operated as inductionheaters. FIG. 149 depicts a cross-sectional end view of an embodiment ofinsulated conductor 574 that is used as an induction heater. FIG. 150depicts a cross-sectional side view of the embodiment depicted in FIG.149. Insulated conductor 574 includes core 542, electrical insulator534, and jacket 540. Core 542 may be copper or another non-ferromagneticelectrical conductor with low resistance that provides little or no heatoutput. In some embodiments, core may be clad with a thin layer ofmaterial such as nickel to inhibit migration of portions of the coreinto electrical insulator 534. Electrical insulator 534 may be magnesiumoxide or another suitable electrical insulator that inhibits arcing athigh voltages.

Jacket 540 includes at least one ferromagnetic material. In certainembodiments, jacket 540 includes carbon steel or another ferromagneticsteel (for example, 410 stainless steel, 446 stainless steel, T/P91stainless steel, T/P92 stainless steel, alloy 52, alloy 42, and Invar36). In some embodiments, jacket 540 includes an outer layer ofcorrosion resistant material (for example, stainless steel such as 347Hstainless steel or 304 stainless steel). The outer layer may be clad tothe ferromagnetic material or otherwise coupled to the ferromagneticmaterial using methods known in the art.

In certain embodiments, jacket 540 has a thickness of at least about 2skin depths of the ferromagnetic material in the jacket. In someembodiments, jacket 540 has a thickness of at least about 3 skin depths,at least about 4 skin depths, or at least about 5 skin depths.Increasing the thickness of jacket 540 may increase the heat output frominsulated conductor 574.

In one embodiment, core 542 is copper with a diameter of about 0.5″(1.27 cm), electrical insulator 534 is magnesium oxide with a thicknessof about 0.20″ (0.5 cm) (the outside diameter is about 0.9″ (2.3 cm)),and jacket 540 is carbon steel with an outside diameter of about 1.6″(4.1 cm) (the thickness is about 0.35″ (0.88 cm)). A thin layer (about0.1″ (0.25 cm) thickness (outside diameter of about 1.7″ (4.3 cm)) ofcorrosion resistant material 347H stainless steel may be clad on theoutside of jacket 540.

In another embodiment, core 542 is copper with a diameter of about0.338″ (0.86 cm), electrical insulator 534 is magnesium oxide with athickness of about 0.096″ (0.24 cm) (the outside diameter is about 0.53″(1.3 cm)), and jacket 540 is carbon steel with an outside diameter ofabout 1.13″ (2.9 cm) (the thickness is about 0.30″ (0.76 cm)). A thinlayer (about 0.065″ (0.17 cm) thickness (outside diameter of about 1.26″(3.2 cm)) of corrosion resistant material 347H stainless steel may beclad on the outside of jacket 540.

In another embodiment, core 542 is copper, electrical insulator 534 ismagnesium oxide, and jacket 540 is a thin layer of copper surrounded bycarbon steel. Core 542, electrical insulator 534, and the thin copperlayer of jacket 540 may be obtained as a single piece of insulatedconductor. Such insulated conductors may be obtained as long pieces ofinsulated conductors (for example, lengths of about 500′ (about 150 m)or more). The carbon steel layer of jacket 540 may be added by drawingdown the carbon steel over the long insulated conductor. Such aninsulated conductor may only generate heat on the outside of jacket 540as the thin copper layer in the jacket shorts to the inside surface ofthe jacket.

In some embodiments, jacket 540 is made of multiple layers offerromagnetic material. The multiple layers may be the sameferromagnetic material or different ferromagnetic materials. Forexample, in one embodiment, jacket 540 is a 0.35″ (0.88 cm) thick carbonsteel jacket made from three layers of carbon steel. The first andsecond layers are 0.10″ (0.25 cm) thick and the third layer is 0.15″(0.38 cm) thick. In another embodiment, jacket 540 is a 0.3″ (0.76 cm)thick carbon steel jacket made from three 0.10″ (0.25 cm) thick layersof carbon steel.

In certain embodiments, jacket 540 and core 542 are electricallyinsulated such that there is no direct electrical connection between thejacket and the core. Core 542 may be electrically coupled to a singlepower source with each end of the core being coupled to one pole of thepower source. For example, insulated conductor 574 may be a u-shapedheater located in a u-shaped wellbore with each end of core 542 beingcoupled to one pole of the power source.

When core 542 is energized with time-varying current, the core induceselectrical current flow on the surfaces of jacket 540 (as shown by thearrows in FIG. 150) due to the ferromagnetic properties of theferromagnetic material in the jacket. In certain embodiments, currentflow is induced on both the inside and outside surfaces of jacket 540.In these induction heater embodiments, jacket 540 operates as theheating element of insulated conductor 574.

At or near the Curie temperature or the phase transformation temperatureof the ferromagnetic material in jacket 540, the magnetic permeabilityof the ferromagnetic material decreases rapidly. When the magneticpermeability of jacket 540 decreases at or near the Curie temperature orthe phase transformation temperature, there is little or no current flowin the jacket because, at these temperatures, the jacket is essentiallynon-ferromagnetic and core 542 is unable to induce current flow in thejacket. With little or no current flow in jacket 540, the temperature ofthe jacket will drop to lower temperatures until the magneticpermeability increases and the jacket becomes ferromagnetic. Thus,jacket 540 self-limits at or near the Curie temperature or the phasetransformation temperature and insulated conductor 574 operates as atemperature limited heater due to the ferromagnetic properties of thejacket. Because current is induced in jacket 540, the turndown ratio maybe higher and the drop in current sharper for the jacket than if currentis directly applied to the jacket.

In certain embodiments, portions of jacket 540 in the overburden of theformation do not include ferromagnetic material (for example, arenon-ferromagnetic). Having the overburden portions of jacket 540 made ofnon-ferromagnetic material inhibits current induction in the overburdenportions of the jackets. Power losses in the overburden are inhibited orreduced by inhibiting current induction in the overburden portions.

FIG. 151 depicts a cross-sectional view of an embodiment of two-leginsulated conductor 574 that is used as an induction heater. FIG. 152depicts a longitudinal cross-sectional view of the embodiment depictedin FIG. 151. Insulated conductor 574 is a two-leg insulated conductorthat includes two cores 542A,B; two electrical insulators 534A,B; andtwo jackets 540A,B. The two legs of insulated conductor 574 may be inphysical contact with each other such that jacket 540A contacts jacket540B along their lengths. Cores 542A,B; electrical insulators 534A,B;and jackets 540A,B may include materials such as those used in theembodiment of insulated conductor 574 depicted in FIGS. 149 and 150.

As shown in FIG. 152, core 542A and core 542B are coupled to transformer580 and terminal block 634. Thus, core 542A and core 542B areelectrically coupled in series such that current in core 542A flows inan opposite direction from current in core 542B, as shown by the arrowsin FIG. 152. Current flow in cores 542A,B induces current flow injackets 540A,B, respectively, as shown by the arrows in FIG. 152.

In certain embodiments, portions of jacket 540A and/or jacket 540B arecoated with an electrically insulating coating (for example, a porcelainenamel coating, alumina coating, and/or alumina-titania coating). Theelectrically insulating coating may inhibit the currents in one jacketfrom affecting current in the other jacket or vice versa (for example,current in one jacket cancelling out current in the other jacket).Electrically insulating the jackets from each other may inhibit theturndown ratio of the heater from being reduced by the interaction ofinduced currents in the jackets.

Because core 542A and core 542B are electrically coupled in series to asingle transformer (transformer 580), insulated conductor 574 may belocated in a wellbore that terminates in the formation (for example, awellbore with a single surface opening such as an L-shaped or J-shapedwellbore). Insulated conductor 574, as depicted in FIG. 152, may beoperated as a subsurface termination induction heater with electricalconnections between the heater and the power source (the transformer)being made through one surface opening.

Portions of jackets 540A,B in the overburden and/or adjacent to portionsof the formation that are not to be significantly heated (for example,thick shale breaks between two hydrocarbon layers) may benon-ferromagnetic to inhibit induction currents in such portions. Thejacket may include one or more sections that are electrically insulatingto restrict induced current flow to heater portions of the insulatedconductor. Inhibiting induction currents in the overburden portion ofthe jackets inhibits inductive heating and/or power losses in theoverburden. Induction effects in other structures in the overburden thatsurround insulated conductor 574 (for example, overburden casings) maybe inhibited because the current in core 542A flows in an oppositedirection from the current in core 542B.

FIG. 153 depicts a cross-sectional view of an embodiment of amultilayered insulated conductor that is used as an induction heater.Insulated conductor 574 includes core 542 surrounded by electricalinsulator 534A and jacket 540A. Electrical insulator 534A and jacket540A comprise a first layer of insulated conductor 574. The first layeris surrounded by a second layer that includes electrical insulator 534Band jacket 540B. Two layers of electrical insulators and jackets areshown in FIG. 153. The insulated conductor may include additional layersas desired. For example, the number of layers may be chosen to provide adesired heat output from the insulated conductor.

Jacket 540A and jacket 540B are electrically insulated from core 542 andeach other by electrical insulator 534A and electrical insulator 534B.Thus, direct flow of current is inhibited between jacket 540A and jacket540B and core 542. When current is applied to core 542, electricalcurrent flow is induced in both jacket 540A and jacket 540B because ofthe ferromagnetic properties of the jackets. Having two or more layersof electrical insulators and jackets provides multiple current inductionloops. The multiple current induction loops may effectively appear aselectrical loads in series to a power source for insulated conductor574. The multiple current induction loops may increase the heatgeneration per unit length of insulated conductor 574 as compared to aninsulated conductor with only one current induction loop. For the sameheat output, the insulated conductor with multiple layers may have ahigher voltage and lower current as compared to the single layerinsulated conductor.

In certain embodiments, jacket 540A and jacket 540B include the sameferromagnetic material. In some embodiments, jacket 540A and jacket 540Binclude different ferromagnetic materials. Properties of jacket 540A andjacket 540B may be varied to provide different heat outputs from thedifferent layers. Examples of properties of jacket 540A and jacket 540Bthat may be varied include, but are not limited to, ferromagneticmaterial and thicknesses of the layers.

Electrical insulators 534A and 534B may be magnesium oxide, porcelainenamel, and/or another suitable electrical insulator. The thicknessesand/or materials of electrical insulators 534A and 534B may be varied toprovide different operating parameters for insulated conductor 574.

FIG. 154 depicts an end view of an embodiment of three insulatedconductors 574 located in a coiled tubing conduit and used as inductionheaters. Insulated conductors 574 may each be, for example, theinsulated conductor depicted in FIGS. 149, 150, and 153. The cores ofinsulated conductors 574 may be coupled to each other such that theinsulated conductors are electrically coupled in a three-phase wyeconfiguration. FIG. 155 depicts a representation of cores 542 ofinsulated conductors 574 coupled together at their ends.

As shown in FIG. 154, insulated conductors 574 are located in tubular702. Tubular 702 may be a coiled tubing conduit or other coiled tubingtubular or casing. Insulated conductors 574 may be in a spiral or helixformation inside tubular 702 to reduce stresses on the insulatedconductors when the insulated conductors are coiled, for example, on acoiled tubing reel. Tubular 702 allows the insulated conductors to beinstalled in the formation using a coiled tubing rig and protects theinsulated conductors during installation into the formation.

FIG. 156 depicts an end view of an embodiment of three insulatedconductors 574 located on a support member and used as inductionheaters. Insulated conductors 574 may each be, for example, theinsulated conductor depicted in FIGS. 149, 150, and 153. The cores ofinsulated conductors 574 may be coupled to each other such that theinsulated conductors are electrically coupled in a three-phase wyeconfiguration. For example, the cores may be coupled together as shownin FIG. 155.

As shown in FIG. 156, insulated conductors 574 are coupled to supportmember 548. Support member 548 provides support for insulated conductors574. Insulated conductors 574 may be wrapped around support member 548in a spiral or helix formation. In some embodiments, support member 548includes ferromagnetic material. Current flow may be induced in theferromagnetic material of support member 548. Thus, support member 548may generate some heat in addition to the heat generated in the jacketsof insulated conductors 574.

In certain embodiments, insulated conductors 574 are held together onsupport member 548 with band 584. Band 584 may be stainless steel oranother non-corrosive material. In some embodiments, band 584 includes aplurality of bands that hold together insulated conductors 574. Thebands may be periodically placed around insulated conductors 574 to holdthe conductors together.

In some embodiments, jacket 540, depicted in FIGS. 149 and 150, orjackets 540A,B, depicted in FIG. 152, include grooves or otherstructures on the outer surface and/or the inner surface of the jacketto increase the effective resistance of the jacket. Increasing theresistance of jacket 540 and/or jackets 540A,B with grooves increasesthe heat generation of the jackets as compared to jackets with smoothsurfaces. Thus, the same electrical current in core 542 and/or cores542A,B will provide more heat output in the grooved surface jackets thanthe smooth surface jackets.

In some embodiments, jacket 540 (such as the jackets depicted in FIGS.149 and 150, or jackets 540A,B depicted in FIG. 152) are divided intosections to provide varying heat outputs along the length of theheaters. For example, jacket 540 and/or jackets 540A,B may be dividedinto sections such as tubular sections 702A, 702B, and 702C, depicted inFIG. 145. The sections of the jackets 540 depicted in FIGS. 149, 150,and 152 may have different properties to provide different heat outputsin each section. Examples of properties that may be varied include, butare not limited to, thicknesses, diameters, resistances, materials,number of grooves, depth of grooves. The different properties in thesections may provide different maximum operating temperatures (forexample, different Curie temperatures or phase transformationtemperatures) along the length of insulated conductor 574. The differentmaximum temperatures of the sections provides different heat outputsfrom the sections.

In certain embodiments, induction heaters include insulated electricalconductors surrounded by spiral wound ferromagnetic materials. Forexample, the spiral wound ferromagnetic materials may operate asinductive heating elements similarly to tubulars 702, depicted in FIGS.140-146. FIG. 157 depicts a representation of an embodiment of aninduction heater with core 542 and electrical insulator 534 surroundedby ferromagnetic layer 708. Core 542 may be copper or anothernon-ferromagnetic electrical conductor with low resistance that provideslittle or no heat output. Electrical insulator 534 may be a polymericelectrical insulator such as Teflon®, XPLE (cross-linked polyethylene),or EPDM (ethylene-propylene diene monomer). In some embodiments, core542 and electrical insulator 534 are obtained together as a polymer(insulator) coated cable. In some embodiments, electrical insulator 534is magnesium oxide or another suitable electrical insulator thatinhibits arcing at high voltages and/or at high temperatures.

In certain embodiments, ferromagnetic layer 708 is spirally wound ontocore 542 and electrical insulator 534. Ferromagnetic layer 708 mayinclude carbon steel or another ferromagnetic steel (for example, 410stainless steel, 446 stainless steel, T/P91 stainless steel, T/P92stainless steel, alloy 52, alloy 42, and Invar 36).

In some embodiments, ferromagnetic layer 708 is spirally wound onto aninsulated conductor. In some embodiments, ferromagnetic layer 708includes an outer layer of corrosion resistant material. In someembodiments, ferromagnetic layer is bar stock. FIG. 158 depicts arepresentation of an embodiment of insulated conductor 574 surrounded byferromagnetic layer 708. Insulated conductor 574 includes core 542,electrical insulator 534, and jacket 540. Core 542 is copper or anothernon-ferromagnetic electrical conductor with low resistance that provideslittle or no heat output. Electrical insulator 534 is magnesium oxide oranother suitable electrical insulator. Ferromagnetic layer 708 isspirally wound onto insulated conductor 574.

Spirally winding ferromagnetic layer 708 onto the heater may increasecontrol over the thickness of the ferromagnetic layer as compared toother construction methods for induction heaters. For example, more thanone ferromagnetic layer 708 may be wound onto the heater to vary theoutput of the heater. The number of ferromagnetic layers 708 may bechosen to provide desired output from the heater. FIG. 159 depicts arepresentation of an embodiment of an induction heater with twoferromagnetic layers 708A,B spirally wound onto core 542 and electricalinsulator 534. In some embodiments, ferromagnetic layer 708A iscounter-wound relative to ferromagnetic layer 708B to provide neutraltorque on the heater. Neutral torque may be useful when the heater issuspended or allowed to hang freely in an opening in the formation.

The number of spiral windings (for example, the number of ferromagneticlayers) may be varied to alter the heat output of the induction heater.In addition, other parameters may be varied to alter the heat output ofthe induction heater. Examples of other varied parameters include, butare not limited to, applied current, applied frequency, geometry,ferromagnetic materials, and thickness and/or number of spiral windings.

Use of spiral wound ferromagnetic layers may allow induction heaters tobe manufactured in continuous long lengths by spiral winding theferromagnetic material onto long lengths of conventional or easilymanufactured insulated cable. Thus, spiral wound induction heaters mayhave reduced manufacturing costs as compared to other induction heaters.The spiral wound ferromagnetic layers may increase the mechanicalflexibility of the induction heater as compared to solid ferromagnetictubular induction heaters. The increased flexibility may allow spiralwound induction heaters to be bent over surface protrusions such ashanger joints.

FIG. 160 depicts an embodiment for assembling ferromagnetic layer 708onto insulated conductor 574. Insulated conductor 574 may be aninsulated conductor cable (for example, mineral insulated conductorcable or polymer insulated conductor cable) or other suitable electricalconductor core covered by insulation.

In certain embodiments, ferromagnetic layer 708 is made of ferromagneticmaterial 1812 fed from reel 1810 and wound onto insulated conductor 574.Reel 1810 may be a coiled tubing rig or other rotatable feed rig. Reel1810 may rotate around insulated conductor 574 as ferromagnetic material1812 is wound onto the insulated conductor to form ferromagnetic layer708. Insulated conductor 574 may be fed from a reel or from a mill asreel 1810 rotates around the insulated conductor.

In some embodiments, ferromagnetic material 1812 is heated prior towinding the material onto insulated conductor 574. For example,ferromagnetic material 1812 may be heated using inductive heater 1814.Pre-heating ferromagnetic material 1812 prior to winding theferromagnetic material may allow the ferromagnetic material to contractand grip onto insulated conductor 574 when the ferromagnetic materialcools.

In some embodiments, portions of casings in the overburden sections ofheater wellbores have surfaces that are shaped to increase the effectivediameter of the casing. Casings in the overburden sections of heaterwellbores may include, but are not limited to, overburden casings,heater casings, heater tubulars, and/or jackets of insulated conductors.Increasing the effective diameter of the casing may reduce inductiveeffects in the casing when current used to power a heater or heatersbelow the overburden is transmitted through the casing (for example,when one phase of power is being transmitted through the overburdensection). When current is transmitted in only one direction through theoverburden, the current may induce other currents in ferromagnetic orother electrically conductive materials such as those found inoverburden casings. These induced currents may provide undesired powerlosses and/or undesired heating in the overburden of the formation.

FIG. 161 depicts an embodiment of casing 710 having a grooved orcorrugated surface. In certain embodiments, casing 710 includes grooves712. In some embodiments, grooves 712 are corrugations or includecorrugations. Grooves 712 may be formed as a part of the surface ofcasing 710 (for example, the casing is formed with grooved surfaces) orthe grooves may be formed by adding or removing (for example, milling)material on the surface of the casing. For example, grooves 712 may belocated on a long piece of tubular that is welded to casing 710.

In certain embodiments, grooves 712 are on the outer surface of casing710. In some embodiments, grooves 712 are on the inner surface of casing710. In some embodiments, grooves 712 are on both the inner and outersurfaces of casing 710.

In certain embodiments, grooves 712 are axial grooves (grooves that golongitudinally along the length of casing 710). In certain embodiments,grooves 712 are straight, angled, or longitudinally spiral. In someembodiments, grooves 712 are substantially axial grooves or spiralgrooves with a significant longitudinal component (i.e., the spiralangle is less than 10°, less than 5°, or less than 1°). In someembodiments, grooves 712 extend substantially axially along the lengthof casing 710. In some embodiments, grooves 712 are evenly spacedgrooves along the surface of casing 710. Grooves 712 may have a varietyof shapes as desired. For example, grooves 712 may have square edges,v-shaped edges, u-shaped edges, rectangular edges, or have roundededges.

Grooves 712 increase the effective circumference of casing 710. Grooves712 increase the effective circumference of casing 710 as compared tothe circumference of a casing with the same inside and outside diametersand smooth surfaces. The depth of grooves 712 may be varied to provide aselected effective circumference of casing 710. For example, axialgrooves that are ¼″ (0.63 cm) wide and ¼″ (0.63 cm) deep, and spaced ¼″(0.63 cm) apart may increase the effective circumference of a 6″ (15.24cm) diameter pipe from 18.84″ (47.85 cm) to 37.68″ (95.71 cm) (or thecircumference of a 12″ (30.48 cm) diameter pipe).

In certain embodiments, grooves 712 increase the effective circumferenceof casing 710 by a factor of at least about 2 as compared to a casingwith the same inside and outside diameters and smooth surfaces. In someembodiments, grooves 712 increase the effective circumference of casing710 by a factor of at least about 3, at least about 4, or at least about6 as compared to a casing with the same inside and outside diameters andsmooth surfaces.

Increasing the effective circumference of casing 710 with grooves 712increases the surface area of the casing. Increasing the surface area ofcasing 710 reduces the induced current in the casing for a given currentflux. Power losses associated with inductive heating in casing 710 arereduced as compared to a casing with smooth surfaces because of thereduced induced current. Thus, the same electrical current will provideless heat output from inductive heating in the axial grooved surfacecasing than the smooth surface casing. Reducing the heat output in theoverburden section of the heater will increase the efficiency of, andreduce the costs associated with, operating the heater. Increasing theeffective circumference of casing 710 and reducing inductive effects inthe casing allows the casing to be made with less expensive materialssuch as carbon steel.

In some embodiments, an electrically insulating coating (for example, aporcelain enamel coating) is placed on one or more surfaces of casing710 to inhibit current and/or power losses from the casing. In someembodiments, casing 710 is formed from two or more longitudinal sectionsof casing (for example, longitudinal sections welded or threadedtogether end to end). The longitudinal sections may be aligned so thatthe grooves on the sections are aligned. Aligning the sections may allowfor cement or other material to flow along the grooves.

In some embodiments, an insulated conductor heater is placed in theformation by itself and the outside of the insulated conductor heater iselectrically isolated from the formation because the heater has littleor no voltage potential on the outside of the heater. FIG. 162 depictsan embodiment of a single-ended, substantially horizontal insulatedconductor heater that electrically isolates itself from the formation.In such an embodiment, heater 438 is insulated conductor 574. Insulatedconductor 574 may be a mineral insulated conductor heater (for example,insulated conductor 574 depicted in FIGS. 163A and 163B). Insulatedconductor 574 is located in opening 556 in hydrocarbon layer 484. Incertain embodiments, opening 556 is an uncased or open wellbore. In someembodiments, opening 556 is a cased or lined wellbore. In someembodiments, insulated conductor heater 574 is a substantially u-shapedheater and is located in a substantially u-shaped opening.

Insulated conductor 574 has little or no current flowing along theoutside surface of the insulated conductor so that the insulatedconductor is electrically isolated from the formation and leaks littleor no current into the formation. The outside surface (or jacket) ofinsulated conductor 574 is a metal or thermal radiating body so thatheat is radiated from the insulated conductor to the formation.

FIGS. 163A and 163B depict cross-sectional representations of anembodiment of insulated conductor 574 that is electrically isolated onthe outside of jacket 540. In certain embodiments, jacket 540 is made offerromagnetic materials. In one embodiment, jacket 540 is made of 410stainless steel. In other embodiments, jacket 540 is made of T/P91 orT/P92 stainless steel. In some embodiments, jacket 540 may includecarbon steel. Core 542 is made of a highly conductive material such ascopper or a copper alloy. Electrical insulator 534 is an electricallyinsulating material such as magnesium oxide. Insulated conductor 574 maybe an inexpensive and easy to manufacture heater.

In the embodiment depicted in FIGS. 163A and 163B, core 542 bringscurrent into the formation, as shown by the arrow. Core 542 and jacket540 are electrically coupled at the distal end (bottom) of the heater.Current returns to the surface of the formation through jacket 540. Theferromagnetic properties of jacket 540 confine the current to the skindepth along the inside diameter of the jacket, as shown by arrows 714 inFIG. 163A. Jacket 540 has a thickness at least 2 or 3 times the skindepth of the ferromagnetic material used in the jacket at 25° C. and atthe design current frequency so that most of the current is confined tothe inside surface of the jacket and little or no current flows on theoutside diameter of the jacket. Thus, there is little or no voltagepotential on the outside of jacket 540. Having little or no voltagepotential on the outside surface of insulated conductor 574 does notexpose the formation to any high voltages, inhibits current leakage tothe formation, and reduces or eliminates the need for isolationtransformers, which decrease energy efficiency.

Because core 542 is made of a highly conductive material such as copperand jacket 540 is made of more resistive ferromagnetic material, amajority of the heat generated by insulated conductor 574 is generatedin the jacket. Generating the majority of the heat in jacket 540increases the efficiency of heat transfer from insulated conductor 574to the formation over an insulated conductor (or other heater) that usesa core or a center conductor to generate the majority of the heat.

In certain embodiments, core 542 is made of copper. Using copper in core542 allows the heating section of the heater and the overburden sectionto have identical core materials. Thus, the heater may be made from onelong core assembly. The long single core assembly reduces or eliminatesthe need for welding joints in the core, which can be unreliable andsusceptible to failure. Additionally, the long, single core assemblyheater may be manufactured remote from the installation site andtransported in a final assembly (ready to install assembly) to theinstallation site. The single core assembly also allows for long heaterlengths (for example, about 1000 m or longer) depending on the breakdownvoltage of the electrical insulator.

In certain embodiments, jacket 540 is made from two or more layers ofthe same materials and/or different materials. Jacket 540 may be formedfrom two or more layers to achieve thicknesses needed for the jacket(for example, to have a thickness at least 3 times the skin depth of theferromagnetic material used in the jacket at 25° C. and at the designcurrent frequency). Manufacturing and/or material limitations may limitthe thickness of a single layer of jacket material. For example, theamount each layer can be strained during manufacturing (forming) thelayer on the heater may limit the thickness of each layer. Thus, toreach jacket thicknesses needed for certain embodiments of insulatedconductor 574, jacket 540 may be formed from several layers of jacketmaterial. For example, three layers of T/P92 stainless steel may be usedto form jacket 540 with a thickness of about 3 times the skin depth ofthe T/P92 stainless steel at 25° C. and at the design current frequency.

In some embodiments, jacket 540 includes two or more differentmaterials. In some embodiments, jacket 540 includes different materialsin different layers of the jacket. For example, jacket 540 may have oneor more inner layers of ferromagnetic material chosen for theirelectrical and/or electromagnetic properties and one or more outerlayers chosen for its non-corrosive properties.

In some embodiments, the thickness of jacket 540 and/or the material ofthe jacket are varied along the heater length. The thickness and/ormaterial of jacket 540 may be varied to vary electrical propertiesand/or mechanical properties along the length of the heater. Forexample, the thickness and/or material of jacket 540 may be varied tovary the turndown ratio or the Curie temperature along the length of theheater. In some embodiments, the inner layer of jacket 540 includescopper or other highly conductive metals in the overburden section ofthe heater. The inner layer of copper limits heat losses in theoverburden section of the heater.

FIGS. 164 and 165 depict an embodiment of insulated conductor 574 insidetubular 702. Insulated conductor 574 may include core 542, electricalinsulator 534, and jacket 540. Core 542 and jacket 540 may beelectrically coupled (shorted) at a distal end of the insulatedconductor. FIG. 166 depicts a cross-sectional representation of anembodiment of the distal end of insulated conductor 574 inside tubular702. Endcap 630 may electrically couple core 542 and jacket 540 totubular 702 at the distal end of insulated conductor 574 and thetubular. Endcap 630 may include electrical conducting materials such ascopper or steel.

In certain embodiments, core 542 is copper, electrical insulator 534 ismagnesium oxide, and jacket 540 is non-ferromagnetic stainless steel(for example, 316H stainless steel, 347H stainless steel, 204-Custainless steel, 201Ln stainless steel, or 204 M stainless steel).Insulated conductor 574 may be placed in tubular 702 to protect theinsulated conductor, increase heat transfer to the formation, and/orallow for coiled tubing or continuous installation of the insulatedconductor. Tubular 702 may be made of ferromagnetic material such as 410stainless steel, T/P 9 alloy steel, T/P91 alloy steel, low alloy steel,or carbon steel. In certain embodiments, tubular 702 is made ofcorrosion resistant materials. In some embodiments, tubular 702 is madeof non-ferromagnetic materials.

In certain embodiments, jacket 540 of insulated conductor 574 islongitudinally welded to tubular 702 along weld joint 716, as shown inFIG. 165. The longitudinal weld may be a laser weld, a tandem GTAW (gastungsten arc welding) weld, or an electron beam weld that welds thesurface of jacket 540 to tubular 702. In some embodiments, tubular 702is made from a longitudinal strip of metal. Tubular 702 may be made byrolling the longitudinal strip to form a cylindrical tube and thenwelding the longitudinal ends of the strip together to make the tubular.

In certain embodiments, insulated conductor 574 is welded to tubular 702as the longitudinal ends of the strip are welded together (in the samewelding process). For example, insulated conductor 574 is placed alongone of the longitudinal ends of the strip so that jacket 540 is weldedto tubular 702 at the location where the ends are welded together. Insome embodiments, insulated conductor 574 is welded to one of thelongitudinal ends of the strip before the strip is rolled to form thecylindrical tube. The ends of the strip may then be welded to formtubular 702.

In some embodiments, insulated conductor 574 is welded to tubular 702 atanother location (for example, at a circumferential location away fromthe weld joining the ends of the strip used to form the tubular). Forexample, jacket 540 of insulated conductor 574 may be welded to tubular702 diametrically opposite from where the longitudinal ends of the stripused to form the tubular are welded. In some embodiments, tubular 702 ismade of multiple strips of material that are rolled together and coupled(for example, welded) to form the tubular with a desired thickness.Using more than one strip of metal may be easier to roll into thecylindrical tube used to form the tubular.

Jacket 540 and tubular 702 may be electrically and mechanically coupledat weld joint 716. Longitudinally welding jacket 540 to tubular 702inhibits arcing between insulated conductor 574 and the tubular. Tubular702 may return electrical current from core 542 along the inside of thetubular if the tubular is ferromagnetic. If tubular 702 isnon-ferromagnetic, a thin electrically insulating layer such as aporcelain enamel coating or a spray coated ceramic may be put on theoutside of the tubular to inhibit current leakage from the tubular intothe formation. In some embodiments, a fluid is placed in tubular 702 toincrease heat transfer between insulated conductor 574 and the tubularand/or to inhibit arcing between the insulated conductor and thetubular. Examples of fluids include, but are not limited to, thermallyconductive gases such as helium, carbon dioxide, or steam. Fluids mayalso include fluids such as oil, molten metals, or molten salts (forexample, solar salt (60% NaNO₃/40% KNO₃)). In some embodiments, heattransfer fluids are transported inside tubular 702 and heated inside thetubular (in the space between the tubular and insulated conductor 574).In some embodiments, an optical fiber, thermocouple, or othertemperature sensor is placed inside tubular 702.

In certain embodiments, the heater depicted in FIGS. 164, 165, and 166is energized with AC current (or time-varying electrical current). Amajority of the heat is generated in tubular 702 when the heater isenergized with AC current. If tubular 702 is ferromagnetic and the wallthickness of the tubular is at least about twice the skin depth at 25°C. and at the design current frequency, then the heater will operate asa temperature limited heater. Generating the majority of the heat intubular 702 improves heat transfer to the formation as compared to aheater that generates a majority of the heat in the insulated conductor.

In certain embodiments, portions of the wellbore that extend through theoverburden include casings. The casings may include materials thatinhibit inductive effects in the casings. Inhibiting inductive effectsin the casings may inhibit induced currents in the casing and/or reduceheat losses to the overburden. In some embodiments, the overburdencasings may include non-metallic materials such as fiberglass,polyvinylchloride (PVC), chlorinated PVC (CPVC), high-densitypolyethylene (HDPE), high temperature polymers (such as nitrogen basedpolymers), or other high temperature plastics. HDPEs with workingtemperatures in a usable range include HDPEs available from Dow ChemicalCo., Inc. (Midland, Mich., U.S.A.). The overburden casings may be madeof materials that are spoolable so that the overburden casings can bespooled into the wellbore. In some embodiments, overburden casings mayinclude non-magnetic metals such as aluminum or non-magnetic alloys suchas manganese steels having at least 10% manganese, iron aluminum alloyswith at least 18% aluminum, or austentitic stainless steels such as 304stainless steel or 316 stainless steel. In some embodiments, overburdencasings may include carbon steel or other ferromagnetic material coupledon the inside diameter to a highly conductive non-ferromagnetic metal(for example, copper or aluminum) to inhibit inductive effects or skineffects. In some embodiments, overburden casings are made of inexpensivematerials that may be left in the formation (sacrificial casings).

In certain embodiments, wellheads for the wellbores may be made of oneor more non-ferromagnetic materials. FIG. 167 depicts an embodiment ofwellhead 718. The components in the wellheads may include fiberglass,PVC, CPVC, HDPE, high temperature polymers (such as nitrogen basedpolymers), and/or non-magnetic alloys or metals. Some materials (such aspolymers) may be extruded into a mold or reaction injection molded (RIM)into the shape of the wellhead. Forming the wellhead from a mold may bea less expensive method of making the wellhead and save in capital costsfor providing wellheads to a treatment site. Using non-ferromagneticmaterials in the wellhead may inhibit undesired heating of components inthe wellhead. Ferromagnetic materials used in the wellhead may beelectrically and/or thermally insulated from other components of thewellhead. In some embodiments, an inert gas (for example, nitrogen orargon) is purged inside the wellhead and/or inside of casings to inhibitreflux of heated gases into the wellhead and/or the casings.

In some embodiments, ferromagnetic materials in the wellhead areelectrically coupled to a non-ferromagnetic material (for example,copper) to inhibit skin effect heat generation in the ferromagneticmaterials in the wellhead. The non-ferromagnetic material is inelectrical contact with the ferromagnetic material so that current flowsthrough the non-ferromagnetic material. In certain embodiments, as shownin FIG. 167, non-ferromagnetic material 720 is coupled (and electricallycoupled) to the inside walls of conduit 552 and wellhead walls 722. Insome embodiments, copper may be plasma sprayed, coated, clad, or linedon the inside and/or outside walls of the wellhead. In some embodiments,a non-ferromagnetic material such as copper is welded, brazed, clad, orotherwise electrically coupled to the inside and/or outside walls of thewellhead. For example, copper may be swaged out to line the inside wallsin the wellhead. Copper may be liquid nitrogen cooled and then allowedto expand to contact and swage against the inside walls of the wellhead.In some embodiments, the copper is hydraulically expanded or explosivelybonded to contact against the inside walls of the wellhead.

In some embodiments, two or more substantially horizontal wellbores arebranched off of a first substantially vertical wellbore drilleddownwards from a first location on a surface of the formation. Thesubstantially horizontal wellbores may be substantially parallel througha hydrocarbon layer. The substantially horizontal wellbores mayreconnect at a second substantially vertical wellbore drilled downwardsat a second location on the surface of the formation. Having multiplewellbores branching off of a single substantially vertical wellboredrilled downwards from the surface reduces the number of openings madeat the surface of the formation.

In certain embodiments, a horizontal heater, or a heater at an inclineis installed in more than one part. FIG. 168 depicts an embodiment ofheater 438 that has been installed in two parts. Heater 438 includesheating section 438A and lead-in section 438B. Heating section 438A maybe located horizontally or at an incline in a hydrocarbon layer in theformation. Lead-in section 438B may be the overburden section or lowresistance section of the heater (for example, the section of the heaterwith little or no electrical heat output).

During installation of heater 438, heating section 438A may be installedfirst into the formation. Heating section 438A may be installed bypushing the heating section into the opening in the formation using adrill pipe or other installation tool that pushes the heating sectioninto the opening. After installation of heating section 438A, theinstallation tool may be removed from the opening in the formation.Installing only heating section 438A with the installation tool at thistime may allow the heating section to be installed further into theformation than if the heating section and the lead-in section areinstalled together because a higher compressive strength may be appliedto the heating section alone (for example, the installation tool onlyhas to push in the horizontal or inclined direction).

In some embodiments, heating section 438A is coupled to mechanicalconnector 692. Connector 692 may be used to hold heating section 438A inthe opening. In some embodiments, connector 692 includes copper or otherelectrically conductive materials so that the connector is used as anelectrical connector (for example, as an electrical ground). In someembodiments, connector 692 is used to couple heating section 438A to abus bar or electrical return rod located in an opening perpendicular tothe opening of the heating section.

Lead-in section 438B may be installed after installation of heatingsection 438A. Lead-in section 438B may be installed with a drill pipe orother installation tool. In some embodiments, the installation tool maybe the same tool used to install heating section 438A.

Lead-in section 438B may couple to heating section 438A as the lead-insection is installed into the opening. In certain embodiments, couplingjoint 724 is used to couple lead-in section 438B to heating section438A. Coupling joint 724 may be located on either lead-in section 438Bor heating section 438A. In some embodiments, coupling joint 724includes portions located on both sections. Coupling joint 724 may be acoupler such as, but not limited to, a wet connect or wet stab. In someembodiments, heating section 438A includes a catcher or other tool thatguides an end of lead-in section 438B to form coupling joint 724.

In some embodiments, coupling joint 724 includes a container (forexample, a can) located on heating section 438A that accepts the end oflead-in section 438B. Electrically conductive beads (for example, balls,spheres, or pebbles) may be located in the container. The beads may movearound as the end of lead-in section 438B is pushed into the containerto make electrical contact between the lead-in section and heatingsection 438A. The beads may be made of, for example, copper or aluminum.The beads may be coated or covered with a corrosion inhibitor such asnickel. In some embodiments, the beads are coated with a solder materialthat melts at lower temperatures (for example, below the boiling pointof water in the formation). A high electrical current may be applied tothe container to melt the solder. The melted solder may flow and fillvoid spaces in the container and be allowed to solidify beforeenergizing the heater. In some embodiments, sacrificial beads are put inthe container. The sacrificial beads may corrode first so that copper oraluminum beads in the container are less likely to be corroded duringoperation of the heater.

Power supplies are used to provide power to downhole power devices(downhole loads) such as, but not limited to, reservoir heaters,electric submersible pumps (ESPs), compressors, electric drills,electrical tools for construction and maintenance, diagnostic systems,sensors, or acoustic wave generators. Surface based power supplies mayhave long supply cabling (power cables) that contribute to problems suchas voltage drops and electrical losses. Thus, it may be necessary toprovide power to the downhole loads at high voltages to reduceelectrical losses. However, many downhole loads are limited by anacceptable supply voltage level to the load. Therefore, an efficienthigh-voltage energy supply may not be viable without furtherconditioning. In such cases, a system for stepping down the voltage fromthe high voltage supply cable to the low voltage load may be necessary.The system may be a transformer.

The electrical power supply for downhole loads is typically providedusing alternating current voltage (AC voltage) from supply grids of 50Hz or 60 Hz frequency. The voltage of the supply grid may correspond tothe voltage of the downhole load. High supply voltages may reduce lossand voltage drop in the supply cable and/or allow the use of supplycables with relatively small cross sections. High supply voltages,however, may cause technical difficulties and require cost intensiveisolation efforts at the load. Voltage drops, electrical losses, andsupply cable cross section limits may limit the length of the supplycable and, thus, the wellbore depth or depth of the downhole load.Locating the transformer downhole may reduce the amount of cablingneeded to provide power to the downhole loads and allow deeper wellboredepths and/or downhole load depths while minimizing voltage drops andelectrical losses in the power system.

Current technical solutions for offshore-applications make use ofsea-bed mounted step-down transformers to reduce cable loss (forexample, “Converter-Fed Subsea Motor Drives”, Raad, R. O.; Henriksen,T.; Raphael, H. B.; Hadler-Jacobsen, A.; Industry Applications, IEEETransactions on Volume 32, Issue 5, September-October 1996 Page(s):1069-1079, which is incorporated by reference as if fully set forthherein). However, these sea-bed mounted transformers may not be usefulto drive downhole loads under solid ground (for example, in a subsurfacewellbore).

FIGS. 169 and 170 depict an embodiment of transformer 580 that may belocated in a subsurface wellbore. FIG. 169 depicts a top viewrepresentation of the embodiment of transformer 580 showing the windingsand core of the transformer. FIG. 170 depicts a side view representationof the embodiment of transformer 580 showing the windings, the core, andthe power leads. Transformer 580 includes primary windings 738A andsecondary windings 738B. Primary windings 738A and secondary windings738B may have different cross-sectional areas.

Core 740 may include two half-shell core sections 740A and 740B aroundprimary windings 738A and secondary windings 738B. In certainembodiments, core sections 740A and 740B are semicircular, symmetricshells. Core sections 740A and 740B may be single pieces that extend thefull length of transformer 580 or the core sections may be assembledfrom multiple shell segments put together (for example, multiple piecesstrung together to make the core sections). In certain embodiments, acore section is formed by putting together the section from two halves.The two halves of the core section may be put together after thewindings, which may be pre-fabricated, are placed in the transformer.

In certain embodiments, core sections 740A and 740B have about the samecross section on the circumference of transformer 580 so that the coreproperly guides the magnetic flux in the transformer. Core sections 740Aand 740B may be made of several layers of core material. Certainorientations of these layers may be designed to minimize eddy currentlosses in transformer 580. In some embodiments, core sections 740A and740B are made of continuous ribbons and windings 738A and 738B are woundinto the core sections.

Transformer 580 may have certain advantages over current transformerconfigurations (such as a toroid core design with the winding on theoutside of the cores). Core sections 740A and 740B have outer surfacesthat offer large surface areas for cooling transformer 580.Additionally, transformer 580 may be sealed so that a cooling liquid maybe continuously run across the outer surfaces of the transformer to coolthe transformer. Transformer 580 may be sealed so that cooling liquidsdo not directly contact the inside of the core and/or the windings. Incertain embodiments, transformer is sealed in an epoxy resin or otherelectrically insulating sealing material. Cooling transformer 580 allowsthe transformer to operate at higher power densities. In certainembodiments, windings 738A and 738B are substantially isolated from coresections 740A and 740B so that the outside surfaces of transformer 580may touch the walls of a wellbore without causing electrical problems inthe wellbore.

In some embodiments, the profile of the core of transformer 580 and/orthe winding window profile are made with clearances to allow foradditional cooling devices, mechanical supports, and/or electricalcontacts on the transformer. In some embodiments, transformer 580 iscoupled to one or more additional transformers in the subsurfacewellbore to increase power in the wellbore and/or phase options in thewellbore. Transformer 580 and/or the phases of the transformer may becoupled to the additional transformers, and/or the varying phases of theadditional transformers, in either series or parallel configurations asneeded to provide power to the downhole load.

FIG. 171 depicts an embodiment of transformer 580 in a wellbore 742.Transformer 580 is located in the overburden section of wellbore 742.The overburden section of wellbore 742 has overburden casing 564.Overburden casing 564 electrically and thermally insulates theoverburden from the inside of wellbore 742. Packing material 566 islocated at the bottom of the overburden section of wellbore 742. Packingmaterial 566 inhibits fluid flow between the overburden section ofwellbore 742 and the heating section of the wellbore.

Power lead 744 may be coupled to transformer 580 and pass throughpacking material 566 to provide power to the downhole load (for example,a downhole heater). In certain embodiments, cooling fluid 746 is locatedin wellbore 742. Transformer 580 may be immersed in cooling fluid 746.Cooling fluid 746 may cool transformer 580 by removing heat from thetransformer and moving the heat away from the transformer. Cooling fluid746 may be circulated in wellbore 742 to increase heat transfer betweentransformer 580 and the cooling fluid. In some embodiments, coolingfluid 746 is circulated to a chiller or other heat exchanger to removeheat from the cooling fluid and maintain a temperature of the coolingfluid at a selected temperature. Maintaining cooling fluid 746 at aselected temperature may provide efficient heat transfer between thecooling fluid and transformer 580 so that the transformer is maintainedat a desired operating temperature.

In certain embodiments, cooling fluid 746 maintains a temperature oftransformer 580 below a selected temperature. The selected temperaturemay be a maximum operating temperature of the transformer. In someembodiments, the selected temperature is a maximum temperature thatallows for a selected operational efficiency of the transformer. In someembodiments, transformer 580 operates at an efficiency of at least 95%,at least 90%, at least 80%, or at least 70% when the transformeroperates below the selected temperature.

In certain embodiments, cooling fluid 746 is water. In some embodiments,cooling fluid 746 is another heat transfer fluid such as, but notlimited to, oil, ammonia, helium, or Freon® (E.I. du Pont de Nemours andCompany, Wilmington, Del., U.S.A.). In some embodiments, the wellboreadjacent to the overburden functions as a heat pipe. Transformer 580boils cooling fluid 746. Vaporized cooling fluid 746 rises in thewellbore, condenses, and flows back to transformer 580. Vaporization ofcooling fluid 746 transfers heat to the cooling fluid and condensationof the cooling fluid allows heat to transfer to the overburden.Transformer 580 may operate near the vaporization temperature of coolingfluid 746.

In some embodiments, cooling fluid is circulated in a pipe thatsurrounds the transformer. The pipe may be in direct thermal contactwith the transformer so that heat is removed from the transformer intothe cooling fluid circulating through the pipe. In some embodiments, thetransformer includes fans, heat sinks, fins, or other devices thatassist in transferring heat away from the transformer. In someembodiments, the transformer is, or includes, a solid state transformerdevice such as an AC to DC converter.

In certain embodiments, the cooling fluid for the downhole transformeris circulated using a heat pipe in the wellbore. FIG. 172 depicts anembodiment of transformer 580 in wellbore 742 with heat pipes 748A,B.Lid 750 is placed at the top of a reservoir of cooling fluid 746 thatsurrounds transformer 580. Heated cooling fluid expands and flows upheat pipe 748A. The heated cooling fluid 746 cools adjacent to theoverburden and flows back to lid 750. The cooled cooling fluid 746 flowsback into the reservoir through heat pipe 748B. Heat pipes 748A,B act tocreate a flow path for the cooling fluid so that the cooling fluidcirculates around transformer 580 and maintains a temperature of thetransformer below the selected temperature.

Computational analysis has shown that a circulated water column wassufficient to cool a 60 Hz transformer that was 125 feet in length andgenerated 80 W/ft of heat. The transformer and the formation wereinitially at ambient temperatures. The water column was initially at anelevated temperature. The water column and transformer cooled over aperiod of about 1 to 2 hours. The transformer initially heated up (butwas still at operable temperatures) but then was cooled by the watercolumn to lower operable temperatures. The computations also showed thatthe transformer would be cooled by the water column when the transformerand the formation were initially at higher than normal temperatures.

Modern utility voltage regulators have microprocessor controllers thatmonitor output voltage and adjust taps up or down to match a desiredsetting. Typical controllers include current monitoring and may beequipped with remote communications capabilities. The controllerfirmware may be modified for current based control (for example, controldesired for maintaining constant wattage as heater resistances vary withtemperature). Load resistance monitoring as well as other electricalanalysis based evaluation and control are a possibility because of theavailability of both current and voltage sensing by the controller. Inaddition to current, sensed electrical properties including, but notlimited to power, voltage, power factor, resistance or harmonics may beused as control parameters. Typical tap changers have a 200% of nominal,short time current rating. Thus, the regulator controller may beprogrammed to respond to overload currents by means of tap changeroperation.

Electronic heater controls such as silicon-controlled rectifiers (SCRs)may be used to provide power to and control subsurface heaters. SCRs maybe expensive to use and may waste electrical energy in the powercircuit. SCRs may also produce harmonic distortions during power controlof the subsurface heaters. Harmonic distortion may put noise on thepower line and stress heaters. In addition, SCRs may overly stressheaters by switching the power between being full on and full off ratherthan regulating the power at or near the ideal current setting. Thus,there may be significant overshooting and/or undershooting at the targetcurrent for temperature limited heaters (for example, heaters usingferromagnetic materials for self-limiting temperature control).

A variable voltage, load tap changing transformer, which is based on aload tap changing regulator design, may be used to provide power to andcontrol subsurface heaters more simply and without the harmonicdistortion associated with electronic heater control. The variablevoltage transformer may be connected to power distribution systems bysimple, inexpensive fused cutouts. The variable voltage transformer mayprovide a cost effective, stand alone, full function heater controllerand isolation transformer.

FIG. 173 depicts a schematic for a conventional design of tap changingvoltage regulator 752. Regulator 752 provides plus or minus 10%adjustment of the input or line voltage. Regulator 752 includes primarywinding 754 and tap changer section 756, which includes the secondarywinding of the regulator. Primary winding 754 is a series windingelectrically coupled to the secondary winding of tap changer section756. Tap changer section 756 includes eight taps 758A-H that separatethe voltage on the secondary winding into voltage steps. Moveable tapchanger 760 is a moveable preventive autotransformer with a balancewinding. Tap changer 760 may be a sliding tap changer that moves betweentaps 758A-H in tap changer section 756. Tap changer 760 may be capableof carrying high currents up to, for example, 668 A or more.

Tap changer 760 contacts either one tap 758 or bridges between two tapsto provide a midpoint between the two tap voltages. Thus, 16 equivalentvoltage steps are created for tap changer 760 to couple to in tapchanger section 756. The voltage steps divide the 10% range ofregulation equally (⅝% per step). Switch 762 changes the voltageadjustment between plus and minus adjustment. Thus, voltage can beregulated plus 10% or minus 10% from the input voltage.

Voltage transformer 764 senses the potential at bushing 766. Thepotential at bushing 766 may be used for evaluation by a microprocessorcontroller. The controller adjusts the tap position to match a presetvalue. Control power transformer 768 provides power to operate thecontroller and the tap changer motor. Current transformer 770 is used tosense current in the regulator.

FIG. 174 depicts a schematic for variable voltage, load tap changingtransformer 772. The schematic for transformer 772 is based on the loadtap changing regulator schematic depicted in FIG. 173. Primary winding754 is isolated from the secondary winding of tap changer section 756 tocreate distinct primary and secondary windings. Primary winding 754 maybe coupled to a voltage source using bushings 774, 776. The voltagesource may provide a first voltage across primary winding 754. The firstvoltage may be a high voltage such as voltages of at least 5 kV, atleast 10 kV, at least 25 kV, or at least 35 kV up to about 50 kV. Thesecondary winding in tap changer section 756 may be coupled to anelectrical load (for example, one or more subsurface heaters) usingbushings 778, 780. The electrical load may include, but not be limitedto, an insulated conductor heater (for example, mineral insulatedconductor heater), a conductor-in-conduit heater, a temperature limitedheater, a dual leg heater, or one heater leg of a three-phase heaterconfiguration. The electrical load may be other than a heater (forexample, a bottom hole assembly for forming a wellbore).

The secondary winding in tap changer section 756 steps down the firstvoltage across primary winding 754 to a second voltage (for example,voltage lower than the first voltage or a second voltage). In certainembodiments, the secondary winding in tap changer section 756 steps downthe voltage from primary winding 754 to the second voltage that isbetween 5% and 20% of the first voltage across the primary winding. Insome embodiments, the secondary winding in tap changer section 756 stepsdown the voltage from primary winding 754 to the second voltage that isbetween 1% and 30% or between 3% and 25% of the first voltage across theprimary winding. In one embodiment, the secondary winding in tap changersection 756 steps down the voltage from primary winding 754 to thesecond voltage that is 10% of the first voltage across the primarywinding. For example, a first voltage of 7200 V across the primarywinding may be stepped down to a second voltage of 720 V across thesecondary winding in tap changer section 756.

In some embodiments, the step down percentage in tap changer section 756is preset. In some embodiments, the step down percentage in tap changersection 756 may be adjusted as needed for desired operation of a loadcoupled to transformer 772.

Taps 758A-H (or any other number of taps) divide the second voltage onthe secondary winding in tap changer section 756 into voltage steps. Thesecond voltage is divided into voltage steps from a selected minimumpercentage of the second voltage up to the full value of the secondvoltage. In certain embodiments, the second voltage is divided intoequivalent voltage steps between the selected minimum percentage and thefull second voltage value. In some embodiments, the selected minimumpercentage is 0% of the second voltage. For example, the second voltagemay be equally divided by the taps in voltage steps ranging between 0 Vand 720 V. In some embodiments, the selected minimum percentage is 25%or 50% of the second voltage.

Transformer 772 includes tap changer 760 that contacts either one tap758 or bridges between two taps to provide a midpoint between the twotap voltages. The position of tap changer 760 on the taps determines thevoltage provided to an electrical load coupled to bushings 778, 780. Asan example, an arrangement with 8 taps in tap changer section 756provides 16 voltage steps for tap changer 760 to couple to in tapchanger section 756. Thus, the electrical load may be provided with 16different voltages varying between the selected minimum percentage andthe second voltage.

In certain embodiments of transformer 772, the voltage steps divide therange between the selected minimum percentage and the second voltageequally (the voltage steps are equivalent). For example, eight taps maydivide a second voltage of 720 V into 16 voltage steps between 0 V and720 V so that each tap increments the voltage provided to the electricalload by 45V. In some embodiments, the voltage steps divide the rangebetween the selected minimum percentage and the second voltage innon-equal increments (the voltage steps are not equivalent).

Switch 762 may be used to electrically disconnect bushing 780 from thesecondary winding and taps 758. Electrically isolating bushing 780 fromthe secondary winding turns off the power (voltage) provided to theelectrical load coupled to bushings 778, 780. Thus, switch 762 providesan internal disconnect in transformer 772 to electrically isolate andturn off power (voltage) to the electrical load coupled to thetransformer.

In transformer 772, voltage transformer 764, control power transformer768, and current transformer 770 are electrically isolated from primarywinding 754. Electrical isolation protects voltage transformer 764,control power transformer 768, and current transformer 770 from currentand/or voltage overloads caused by primary winding 754.

In certain embodiments, transformer 772 is used to provide power to avariable electrical load (for example, a subsurface heater such as, butnot limited to, a temperature limited heater using ferromagneticmaterial that self-limits at the Curie temperature or a phase transitiontemperature range). Transformer 772 allows power to the electrical loadto be adjusted in small voltage increments (voltage steps) by moving tapchanger 760 between taps 758. Thus, the voltage supplied to theelectrical load may be adjusted incrementally to provide constantcurrent to the electrical load in response to changes in the electricalload (for example, changes in resistance of the electrical load).Voltage to the electrical load may be controlled from a minimum voltage(the selected minimum percentage) up to full potential (the secondvoltage) in increments. The increments may be equal increments ornon-equal increments. Thus, power to the electrical load does not haveto be turned full on or off to control the electrical load such as isdone with a SCR controller. Using small increments may reduce cyclingstress on the electrical load and may increase the lifetime of thedevice that is the electrical load. Transformer 772 changes the voltageusing mechanical operation instead of the electrical switching used inSCRs. Electrical switching can add harmonics and/or noise to the voltagesignal provided to the electrical load. The mechanical switching oftransformer 772 provides clean, noise free, incrementally adjustablecontrol of the voltage provided to the electrical load.

Transformer 772 may be controlled by controller 782. Controller 782 maybe a microprocessor controller. Controller 782 may be powered by controlpower transformer 768. Controller 782 may assess properties oftransformer 772, including tap changer section 756, and/or theelectrical load coupled to the transformer. Examples of properties thatmay be assessed by controller 782 include, but are not limited to,voltage, current, power, power factor, harmonics, tap change operationcount, maximum and minimum value recordings, wear of the tap changercontacts, and electrical load resistance.

In certain embodiments, controller 782 is coupled to the electrical loadto assess properties of the electrical load. For example, controller 782may be coupled to the electrical load using an optical fiber. Theoptical fiber allows measurement of properties of the electrical loadsuch as, but not limited to, electrical resistance, impedance,capacitance, and/or temperature. In some embodiments, controller 782 iscoupled to voltage transformer 764 and/or current transformer 770 toassess the voltage and/or current output of transformer 772. In someembodiments, the voltage and current are used to assess a resistance ofthe electrical load over one or more selected time periods. In someembodiments, the voltage and current are used to assess or diagnoseother properties of the electrical load (for example, temperature).

In certain embodiments, controller 782 adjusts the voltage output oftransformer 772 in response to changes in the electrical load coupled tothe transformer or other changes in the power distribution system suchas, but not limited to, input voltage to the primary winding or otherpower supply changes. For example, controller 782 may adjust the voltageoutput of transformer 772 in response to changes in the electricalresistance of the electrical load. Controller 782 may adjust the outputvoltage by controlling the movement of control tap changer 760 betweentaps 758 to adjust the voltage output of transformer 772. In someembodiments, controller 782 adjusts the voltage output of transformer772 so that the electrical load (for example, a subsurface heater) isoperated at a relatively constant current. In some embodiments,controller 782 may adjust the voltage output of transformer 772 bymoving tap changer 760 to a new tap, assess the resistance and/or powerat the new tap, and move the tap changer to another new tap if needed.

In some embodiments, controller 782 assesses the electrical resistanceof the load (for example, by measuring the voltage and current using thevoltage and current transformers or by measuring the resistance of theelectrical load using the optical fiber) and compares the assessedelectrical resistance to a theoretical resistance. Controller 782 mayadjust the voltage output of transformer 772 in response to differencesbetween the assessed resistance and the theoretical resistance. In someembodiments, the theoretical resistance is an ideal resistance foroperation of the electrical load. In some embodiments, the theoreticalresistance varies over time due to other changes in the electrical load(for example, temperature of the electrical load).

In some embodiments, controller 782 is programmable to cycle tap changer760 between two or more taps 758 to achieve intermediate voltage outputs(for example, a voltage output between two tap voltage outputs).Controller 782 may adjust the time tap changer 760 is on each of thetaps cycled between to obtain an average voltage at or near the desiredintermediate voltage output. For example, controller 782 may keep tapchanger 760 at two taps approximately 50% of the time each to maintainan average voltage approximately midway between the voltages at the twotaps.

In some embodiments, controller 782 is programmable to limit the numbersof voltage changes (movement of tap changer 760 between taps 758 orcycles of tap changes) over a period of time. For example, controller782 may only allow 1 tap change every 30 minutes or 2 tap changes perhour. Limiting the number of tap changes over the period of time reducesthe stress on the electrical load (for example, a heater) from changesin voltage to the load. Reducing the stresses applied to the electricalload may increase the lifetime of the electrical load. Limiting thenumber of tap changes may also increase the lifetime of the tap changerapparatus. In some embodiments, the number of tap changes over theperiod of time is adjustable using the controller. For example, a usermay be allowed to adjust the cycle limit for tap changes on transformer772.

In some embodiments, controller 782 is programmable to power theelectrical load in a start up sequence. For example, subsurface heatersmay require a certain start up protocol (such as high current duringearly times of heating and lower current as the temperature of theheater reaches a set point). Ramping up power to the heaters in adesired procedure may reduce mechanical stresses on the heaters frommaterials expanding at different rates. In some embodiments, controller782 ramps up power to the electrical load with controlled increases involtage steps over time. In some embodiments, controller 782 ramps uppower to the electrical load with controlled increases in watts perhour. Controller 782 may be programmed to automatically start up theelectrical load according to a user input start up procedure or apre-programmed start up procedure.

In some embodiments, controller 782 is programmable to turn off power tothe electrical load in a shut down sequence. For example, subsurfaceheaters may require a certain shut down protocol to inhibit the heatersfrom cooling to quickly. Controller 782 may be programmed toautomatically shut down the electrical load according to a user inputshut down procedure or a pre-programmed shut down procedure.

In some embodiments, controller 782 is programmable to power theelectrical load in a moisture removal sequence. For example, subsurfaceheaters or motors may require start up at second voltages to removemoisture from the system before application of higher voltages. In someembodiments, controller 782 inhibits increases in voltage until requiredelectrical load resistance values are met. Limiting increases in voltagemay inhibit transformer 772 from applying voltages that cause shortingdue to moisture in the system. Controller 782 may be programmed toautomatically start up the electrical load according to a user inputmoisture removal sequence or a pre-programmed moisture removalprocedure.

In some embodiments, controller 782 is programmable to reduce power tothe electrical load based on changes in the voltage input to primarywinding 754. For example, the power to the electrical load may bereduced during brownouts or other power supply shortages. Reducing thepower to the electrical load may compensate for the reduced powersupply.

In some embodiments, controller 782 is programmable to protect theelectrical load from being overloaded. Controller 782 may be programmedto automatically and immediately reduce the voltage output if thecurrent to the electrical load increases above a selected value. Thevoltage output may be stepped down as fast as possible while sensing thecurrent. Sensing of the current occurs on a faster time scale than thestep downs in voltage so the voltage may be stepped down as fast aspossible until the current drops below a selected level. In someembodiments, tap changes (voltage steps) may be inhibited above highercurrent levels. At the higher current levels, secondary fusing may beused to limit the current. Reducing the tap setting in response to thehigher current levels may allow for continued operation of thetransformer even after partial failure or quenching of electrical loadssuch as heaters.

In some embodiments, controller 782 records or tracks data from theoperation of the electrical load and/or transformer 772. For example,controller 782 may record changes in the resistance or other propertiesof the electrical load or transformer 772. In some embodiments,controller 782 records faults in operation of transformer 772 (forexample, missed step changes).

In certain embodiments, controller 782 includes communication modules.The communication modules may be programmed to provide status, data,and/or diagnostics for any device or system coupled to the controllersuch as the electrical load or transformer 772. The communicationmodules may communicate using RS485 serial communication, Ethernet,fiber, wireless, and/or other communication technologies known in theart. The communication modules may be used to transmit informationremotely to another site so that controller 782 and transformer 772 areoperated in a self-contained or automatic manner but are able to reportto another location (for example, a central monitoring location). Thecentral monitoring location may monitor several controllers andtransformers (for example, controllers and transformers located in ahydrocarbon processing field). In some embodiments, users or equipmentat the central monitoring location are able to remotely operate one ormore of the controllers using the communications modules.

FIG. 175 depicts a representation of an embodiment of transformer 772and controller 782. In certain embodiments, transformer 772 is enclosedin enclosure 784. Enclosure 784 may be a cylindrical can. Enclosure 784may be any other suitable enclosure known in the art (for example, asubstation style rectangular enclosure). Controller 782 may be mountedto the outside of enclosure 784. Bushings 774, 776, 778, and 780 may beopen air, high voltage bushings located on the outside of enclosure 784for coupling transformer 772 to the power supply and the electricalload.

In certain embodiments, enclosure 784 is mounted on a pole or otherwisesupported off the ground. In some embodiments, one or more enclosures784 are mounted on an elevated platform supported by a pole or elevatedmounting support. Mounting enclosure 784 on a pole or mounting supportincreases air circulation around and in the enclosure and transformer772. Increasing air circulation decreases operating temperatures andincreases efficiency of the transformer. In certain embodiments,components of transformer 772 are coupled to the top of enclosure 784 sothat the components are removed as a single unit from the enclosure byremoving the top of the enclosure.

In certain embodiments, three transformers 772 are used to operatethree, or multiples of three, electrical loads in a three-phaseconfiguration. The three transformers may be monitored to assess if thetap positions in each transformer are in sync (at the same tapposition). In some embodiments, one controller 782 is used to controlthe three transformers. The controller may monitor the transformers toensure that the transformers are in sync.

In certain embodiments, a temperature limited heater is utilized forheavy oil applications (for example, treatment of relatively permeableformations or tar sands formations). A temperature limited heater mayprovide a relatively low Curie temperature and/or phase transformationtemperature range so that a maximum average operating temperature of theheater is less than 350° C., 300° C., 250° C., 225° C., 200° C., or 150°C. In an embodiment (for example, for a tar sands formation), a maximumtemperature of the temperature limited heater is less than about 250° C.to inhibit olefin generation and production of other cracked products.In some embodiments, a maximum temperature of the temperature limitedheater is above about 250° C. to produce lighter hydrocarbon products.In some embodiments, the maximum temperature of the heater may be at orless than about 500° C.

A heater may heat a volume of formation adjacent to a productionwellbore (a near production wellbore region) so that the temperature offluid in the production wellbore and in the volume adjacent to theproduction wellbore is less than the temperature that causes degradationof the fluid. The heat source may be located in the production wellboreor near the production wellbore. In some embodiments, the heat source isa temperature limited heater. In some embodiments, two or more heatsources may supply heat to the volume. Heat from the heat source mayreduce the viscosity of crude oil in or near the production wellbore. Insome embodiments, heat from the heat source mobilizes fluids in or nearthe production wellbore and/or enhances the flow of fluids to theproduction wellbore. In some embodiments, reducing the viscosity ofcrude oil allows or enhances gas lifting of heavy oil (at most about 10°API gravity oil) or intermediate gravity oil (approximately 12° to 20°API gravity oil) from the production wellbore. In certain embodiments,the initial API gravity of oil in the formation is at most 10°, at most20°, at most 25°, or at most 30°. In certain embodiments, the viscosityof oil in the formation is at least 0.05 Pa·s (50 cp). In someembodiments, the viscosity of oil in the formation is at least 0.10 Pa·s(100 cp), at least 0.15 Pa·s (150 cp), or at least at least 0.20 Pa·s(200 cp). Large amounts of natural gas may have to be utilized toprovide gas lift of oil with viscosities above 0.05 Pa·s. Reducing theviscosity of oil at or near the production wellbore in the formation toa viscosity of 0.05 Pa·s (50 cp), 0.03 Pa·s (30 cp), 0.02 Pa·s (20 cp),0.01 Pa·s (10 cp), or less (down to 0.001 Pa·s (1 cp) or lower) lowersthe amount of natural gas or other fluid needed to lift oil from theformation. In some embodiments, reduced viscosity oil is produced byother methods such as pumping.

The rate of production of oil from the formation may be increased byraising the temperature at or near a production wellbore to reduce theviscosity of the oil in the formation in and adjacent to the productionwellbore. In certain embodiments, the rate of production of oil from theformation is increased by 2 times, 3 times, 4 times, or greater overstandard cold production with no external heating of formation duringproduction. Certain formations may be more economically viable forenhanced oil production using the heating of the near productionwellbore region. Formations that have a cold production rateapproximately between 0.05 m³/(day per meter of wellbore length) and0.20 m³/(day per meter of wellbore length) may have significantimprovements in production rate using heating to reduce the viscosity inthe near production wellbore region. In some formations, productionwells up to 775 m, up to 1000 m, or up to 1500 m in length are used.Thus, a significant increase in production is achievable in someformations. Heating the near production wellbore region may be used informations where the cold production rate is not between 0.05 m³/(dayper meter of wellbore length) and 0.20 m³/(day per meter of wellborelength), but heating such formations may not be as economicallyfavorable. Higher cold production rates may not be significantlyincreased by heating the near wellbore region, while lower productionrates may not be increased to an economically useful value.

Using the temperature limited heater to reduce the viscosity of oil ator near the production well inhibits problems associated withnon-temperature limited heaters and heating the oil in the formation dueto hot spots. One possible problem is that non-temperature limitedheaters can cause coking of oil at or near the production well if theheater overheats the oil because the heaters are at too high atemperature. Higher temperatures in the production well may also causebrine to boil in the well, which may lead to scale formation in thewell. Non-temperature limited heaters that reach higher temperatures mayalso cause damage to other wellbore components (for example, screensused for sand control, pumps, or valves). Hot spots may be caused byportions of the formation expanding against or collapsing on the heater.In some embodiments, the heater (either the temperature limited heateror another type of non-temperature limited heater) has sections that arelower because of sagging over long heater distances. These lowersections may sit in heavy oil or bitumen that collects in lower portionsof the wellbore. At these lower sections, the heater may develop hotspots due to coking of the heavy oil or bitumen. A standardnon-temperature limited heater may overheat at these hot spots, thusproducing a non-uniform amount of heat along the length of the heater.Using the temperature limited heater may inhibit overheating of theheater at hot spots or lower sections and provide more uniform heatingalong the length of the wellbore.

In certain embodiments, fluids in the relatively permeable formationcontaining heavy hydrocarbons are produced with little or nopyrolyzation of hydrocarbons in the formation. In certain embodiments,the relatively permeable formation containing heavy hydrocarbons is atar sands formation. For example, the formation may be a tar sandsformation such as the Athabasca tar sands formation in Alberta, Canadaor a carbonate formation such as the Grosmont carbonate formation inAlberta, Canada. The fluids produced from the formation are mobilizedfluids. Producing mobilized fluids may be more economical than producingpyrolyzed fluids from the tar sands formation. Producing mobilizedfluids may also increase the total amount of hydrocarbons produced fromthe tar sands formation.

FIGS. 176-179 depict side view representations of embodiments forproducing mobilized fluids from tar sands formations. In FIGS. 176-179,heaters 438 have substantially horizontal heating sections inhydrocarbon layer 484 (as shown, the heaters have heating sections thatgo into and out of the page). Hydrocarbon layer 484 may be belowoverburden 482. FIG. 176 depicts a side view representation of anembodiment for producing mobilized fluids from a tar sands formationwith a relatively thin hydrocarbon layer. FIG. 177 depicts a side viewrepresentation of an embodiment for producing mobilized fluids from ahydrocarbon layer that is thicker than the hydrocarbon layer depicted inFIG. 176. FIG. 178 depicts a side view representation of an embodimentfor producing mobilized fluids from a hydrocarbon layer that is thickerthan the hydrocarbon layer depicted in FIG. 177. FIG. 179 depicts a sideview representation of an embodiment for producing mobilized fluids froma tar sands formation with a hydrocarbon layer that has a shale break.

In FIG. 176, heaters 438 are placed in an alternating triangular patternin hydrocarbon layer 484. In FIGS. 177, 178, and 179, heaters 438 areplaced in an alternating triangular pattern in hydrocarbon layer 484that repeats vertically to encompass a majority or all of thehydrocarbon layer. In FIG. 179, the alternating triangular pattern ofheaters 438 in hydrocarbon layer 484 repeats uninterrupted across shalebreak 786. In FIGS. 176-179, heaters 438 may be equidistantly spacedfrom each other. In the embodiments depicted in FIGS. 176-179, thenumber of vertical rows of heaters 438 depends on factors such as, butnot limited to, the desired spacing between the heaters, the thicknessof hydrocarbon layer 484, and/or the number and location of shale breaks786. In some embodiments, heaters 438 are arranged in other patterns.For example, heaters 438 may be arranged in patterns such as, but notlimited to, hexagonal patterns, square patterns, or rectangularpatterns.

In the embodiments depicted in FIGS. 176-179, heaters 438 provide heatthat mobilizes hydrocarbons (reduces the viscosity of the hydrocarbons)in hydrocarbon layer 484. In certain embodiments, heaters 438 provideheat that reduces the viscosity of the hydrocarbons in hydrocarbon layer484 below about 0.50 Pa·s (500 cp), below about 0.10 Pa·s (100 cp), orbelow about 0.05 Pa·s (50 cp). The spacing between heaters 438 and/orthe heat output of the heaters may be designed and/or controlled toreduce the viscosity of the hydrocarbons in hydrocarbon layer 484 todesirable values. Heat provided by heaters 438 may be controlled so thatlittle or no pyrolyzation occurs in hydrocarbon layer 484. Superpositionof heat between the heaters may create one or more drainage paths (forexample, paths for flow of fluids) between the heaters. In certainembodiments, production wells 206A and/or production wells 206B arelocated proximate heaters 438 so that heat from the heaters superimposesover the production wells. The superimposition of heat from heaters 438over production wells 206A and/or production wells 206B creates one ormore drainage paths from the heaters to the production wells. In certainembodiments, one or more of the drainage paths converge. For example,the drainage paths may converge at or near a bottommost heater and/orthe drainage paths may converge at or near production wells 206A and/orproduction wells 206B. Fluids mobilized in hydrocarbon layer 484 tend toflow towards the bottommost heaters 438, production wells 206A and/orproduction wells 206B in the hydrocarbon layer because of gravity andthe heat and pressure gradients established by the heaters and/or theproduction wells. The drainage paths and/or the converged drainage pathsallow production wells 206A and/or production wells 206B to collectmobilized fluids in hydrocarbon layer 484.

In certain embodiments, hydrocarbon layer 484 has sufficientpermeability to allow mobilized fluids to drain to production wells 206Aand/or production wells 206B. For example, hydrocarbon layer 484 mayhave a permeability of at least about 0.1 darcy, at least about 1 darcy,at least about 10 darcy, or at least about 100 darcy. In someembodiments, hydrocarbon layer 484 has a relatively large verticalpermeability to horizontal permeability ratio (K_(v)/K_(h)). Forexample, hydrocarbon layer 484 may have a K_(v)/K_(h) ratio betweenabout 0.01 and about 2, between about 0.1 and about 1, or between about0.3 and about 0.7.

In certain embodiments, fluids are produced through production wells206A located near heaters 438 in the lower portion of hydrocarbon layer484. In some embodiments, fluids are produced through production wells206B located below and approximately midway between heaters 438 in thelower portion of hydrocarbon layer 484. At least a portion of productionwells 206A and/or production wells 206B may be oriented substantiallyhorizontal in hydrocarbon layer 484 (as shown in FIGS. 176-179, theproduction wells have horizontal portions that go into and out of thepage). Production wells 206A and/or 206B may be located proximate lowerportion heaters 438 or the bottommost heaters.

In some embodiments, production wells 206A are positioned substantiallyvertically below the bottommost heaters in hydrocarbon layer 484.Production wells 206A may be located below heaters 438 at the bottomvertex of a pattern of the heaters (for example, at the bottom vertex ofthe triangular pattern of heaters depicted in FIGS. 176-179). Locatingproduction wells 206A substantially vertically below the bottommostheaters may allow for efficient collection of mobilized fluids fromhydrocarbon layer 484.

In certain embodiments, the bottommost heaters are located between about2 m and about 10 m from the bottom of hydrocarbon layer 484, betweenabout 4 m and about 8 m from the bottom of the hydrocarbon layer, orbetween about 5 m and about 7 m from the bottom of the hydrocarbonlayer. In certain embodiments, production wells 206A and/or productionwells 206B are located at a distance from the bottommost heaters 438that allows heat from the heaters to superimpose over the productionwells but at a distance from the heaters that inhibits coking at theproduction wells. Production wells 206A and/or production wells 206B maybe located a distance from the nearest heater (for example, thebottommost heater) of at most ¾ of the spacing between heaters in thepattern of heaters (for example, the triangular pattern of heatersdepicted in FIGS. 176-179). In some embodiments, production wells 206Aand/or production wells 206B are located a distance from the nearestheater of at most ⅔, at most ½, or at most ⅓ of the spacing betweenheaters in the pattern of heaters. In certain embodiments, productionwells 206A and/or production wells 206B are located between about 2 mand about 10 m from the bottommost heaters, between about 4 m and about8 m from the bottommost heaters, or between about 5 m and about 7 m fromthe bottommost heaters. Production wells 206A and/or production wells206B may be located between about 0.5 m and about 8 m from the bottom ofhydrocarbon layer 484, between about 1 m and about 5 m from the bottomof the hydrocarbon layer, or between about 2 m and about 4 m from thebottom of the hydrocarbon layer.

In some embodiments, at least some production wells 206A are locatedsubstantially vertically below heaters 438 near shale break 786, asdepicted in FIG. 179. Production wells 206A may be located betweenheaters 438 and shale break 786 to produce fluids that flow and collectabove the shale break. Shale break 786 may be an impermeable barrier inhydrocarbon layer 484. In some embodiments, shale break 786 has athickness between about 1 m and about 6 m, between about 2 m and about 5m, or between about 3 m and about 4 m. Production wells 206A betweenheaters 438 and shale break 786 may produce fluids from the upperportion of hydrocarbon layer 484 (above the shale break) and productionwells 206A below the bottommost heaters in the hydrocarbon layer mayproduce fluids from the lower portion of the hydrocarbon layer (belowthe shale break), as depicted in FIG. 179. In some embodiments, two ormore shale breaks may exist in a hydrocarbon layer. In such anembodiment, production wells are placed at or near each of the shalebreaks to produce fluids flowing and collecting above the shale breaks.

In some embodiments, shale break 786 breaks down (is desiccated ordecomposes) as the shale break is heated by heaters 438 on either sideof the shale break. As shale break 786 breaks down, the permeability ofthe shale break increases and fluids flow through the shale break. Oncefluids are able to flow through shale break 786, production wells abovethe shale break may not be needed for production as fluids can flow toproduction wells at or near the bottom of hydrocarbon layer 484 and beproduced there.

In certain embodiments, the bottommost heaters above shale break 786 arelocated between about 2 m and about 10 m from the shale break, betweenabout 4 m and about 8 m from the bottom of the shale break, or betweenabout 5 m and about 7 m from the shale break. Production wells 206A maybe located between about 2 m and about 10 m from the bottommost heatersabove shale break 786, between about 4 m and about 8 m from thebottommost heaters above the shale break, or between about 5 m and about7 m from the bottommost heaters above the shale break. Production wells206A may be located between about 0.5 m and about 8 m from shale break786, between about 1 m and about 5 m from the shale break, or betweenabout 2 m and about 4 m from the shale break.

In some embodiments, heat is provided in production wells 206A and/orproduction wells 206B, depicted in FIGS. 176-179. Providing heat inproduction wells 206A and/or production wells 206B may maintain and/orenhance the mobility of the fluids in the production wells. Heatprovided in production wells 206A and/or production wells 206B maysuperimpose with heat from heaters 438 to create the flow path from theheaters to the production wells. In some embodiments, production wells206A and/or production wells 206B include a pump to move fluids to thesurface of the formation. In some embodiments, the viscosity of fluids(oil) in production wells 206A and/or production wells 206B is loweredusing heaters and/or diluent injection (for example, using a conduit inthe production wells for injecting the diluent).

In certain embodiments, in situ heat treatment of the relativelypermeable formation containing hydrocarbons (for example, the tar sandsformation) includes heating the formation to visbreaking temperatures.For example, the formation may be heated to temperatures between about100° C. and 260° C., between about 150° C. and about 250° C., betweenabout 200° C. and about 240° C., between about 205° C. and 230° C.,between about 210° C. and 225° C. In one embodiment, the formation isheated to a temperature of about 220° C. In one embodiment, theformation is heated to a temperature of about 230° C. At visbreakingtemperatures, fluids in the formation have a reduced viscosity (versustheir initial viscosity at initial formation temperature) that allowsfluids to flow in the formation. The reduced viscosity at visbreakingtemperatures may be a permanent reduction in viscosity as thehydrocarbons go through a step change in viscosity at visbreakingtemperatures (versus heating to mobilization temperatures, which mayonly temporarily reduce the viscosity). The visbroken fluids may haveAPI gravities that are relatively low (for example, at most about 10°,about 12°, about 15°, or about 19° API gravity), but the API gravitiesare higher than the API gravity of non-visbroken fluid from theformation. The non-visbroken fluid from the formation may have an APIgravity of 7° or less.

In some embodiments, heaters in the formation are operated at full poweroutput to heat the formation to visbreaking temperatures or highertemperatures. Operating at full power may rapidly increase the pressurein the formation. In certain embodiments, fluids are produced from theformation to maintain a pressure in the formation below a selectedpressure as the temperature of the formation increases. In someembodiments, the selected pressure is a fracture pressure of theformation. In certain embodiments, the selected pressure is betweenabout 1000 kPa and about 15000 kPa, between about 2000 kPa and about10000 kPa, or between about 2500 kPa and about 5000 kPa. In oneembodiment, the selected pressure is about 10000 kPa. Maintaining thepressure as close to the fracture pressure as possible may minimize thenumber of production wells needed for producing fluids from theformation.

In certain embodiments, treating the formation includes maintaining thetemperature at or near visbreaking temperatures (as described above)during the entire production phase while maintaining the pressure belowthe fracture pressure. The heat provided to the formation may be reducedor eliminated to maintain the temperature at or near visbreakingtemperatures. Heating to visbreaking temperatures but maintaining thetemperature below pyrolysis temperatures or near pyrolysis temperatures(for example, below about 230° C.) inhibits coke formation and/or higherlevel reactions. Heating to visbreaking temperatures at higher pressures(for example, pressures near but below the fracture pressure) keepsproduced gases in the liquid oil (hydrocarbons) in the formation andincreases hydrogen reduction in the formation with higher hydrogenpartial pressures. Heating the formation to only visbreakingtemperatures also uses less energy input than heating the formation topyrolysis temperatures.

Fluids produced from the formation may include visbroken fluids,mobilized fluids, and/or pyrolyzed fluids. In some embodiments, aproduced mixture that includes these fluids is produced from theformation. The produced mixture may have assessable properties (forexample, measurable properties). The produced mixture properties aredetermined by operating conditions in the formation being treated (forexample, temperature and/or pressure in the formation). In certainembodiments, the operating conditions may be selected, varied, and/ormaintained to produce desirable properties in hydrocarbons in theproduced mixture. For example, the produced mixture may includehydrocarbons that have properties that allow the mixture to be easilytransported (for example, sent through a pipeline without adding diluentor blending the mixture and/or resulting hydrocarbons with anotherfluid).

In some embodiments, after the formation reaches visbreakingtemperatures, the pressure in the formation is reduced. In certainembodiments, the pressure in the formation is reduced at temperaturesabove visbreaking temperatures. Reducing the pressure at highertemperatures allows more of the hydrocarbons in the formation to beconverted to higher quality hydrocarbons by visbreaking and/orpyrolysis. Allowing the formation to reach higher temperatures beforepressure reduction, however, may increase the amount of carbon dioxideproduced and/or the amount of coking in the formation. For example, insome formations, coking of bitumen (at pressures above 700 kPa) beginsat about 280° C. and reaches a maximum rate at about 340° C. Atpressures below about 700 kPa, the coking rate in the formation isminimal. Allowing the formation to reach higher temperatures beforepressure reduction may decrease the amount of hydrocarbons produced fromthe formation.

In certain embodiments, the temperature in the formation (for example,an average temperature of the formation) when the pressure in theformation is reduced is selected to balance one or more factors. Thefactors considered may include: the quality of hydrocarbons produced,the amount of hydrocarbons produced, the amount of carbon dioxideproduced, the amount hydrogen sulfide produced, the degree of coking inthe formation, and/or the amount of water produced. Experimentalassessments using formation samples and/or simulated assessments basedon the formation properties may be used to assess results of treatingthe formation using the in situ heat treatment process. These resultsmay be used to determine a selected temperature, or temperature range,for when the pressure in the formation is to be reduced. The selectedtemperature, or temperature range, may also be affected by factors suchas, but not limited to, hydrocarbon or oil market conditions and othereconomic factors. In certain embodiments, the selected temperature is ina range between about 275° C. and about 305° C., between about 280° C.and about 300° C., or between about 285° C. and about 295° C.

In certain embodiments, an average temperature in the formation isassessed from an analysis of fluids produced from the formation. Forexample, the average temperature of the formation may be assessed froman analysis of the fluids that have been produced to maintain thepressure in the formation below the fracture pressure of the formation.

In some embodiments, values of the hydrocarbon isomer shift in fluids(for example, gases) produced from the formation is used to indicate theaverage temperature in the formation. Experimental analysis and/orsimulation may be used to assess one or more hydrocarbon isomer shiftsand relate the values of the hydrocarbon isomer shifts to the averagetemperature in the formation. The assessed relation between thehydrocarbon isomer shifts and the average temperature may then be usedin the field to assess the average temperature in the formation bymonitoring one or more of the hydrocarbon isomer shifts in fluidsproduced from the formation. In some embodiments, the pressure in theformation is reduced when the monitored hydrocarbon isomer shift reachesa selected value. The selected value of the hydrocarbon isomer shift maybe chosen based on the selected temperature, or temperature range, inthe formation for reducing the pressure in the formation and theassessed relation between the hydrocarbon isomer shift and the averagetemperature. Examples of hydrocarbon isomer shifts that may be assessedinclude, but are not limited to, n-butane-δ¹³C₄ percentage versuspropane-δ¹³C₃ percentage, n-pentane-δ¹³C₅ percentage versuspropane-δ¹³C₃ percentage, n-pentane-δ¹³C₅ percentage versusn-butane-δ¹³C₄ percentage, and i-pentane-δ¹³C₅ percentage versusi-butane-δ¹³C₄ percentage. In some embodiments, the hydrocarbon isomershift in produced fluids is used to indicate the amount of conversion(for example, amount of pyrolysis) that has taken place in theformation.

In some embodiments, weight percentages of saturates in fluids producedfrom the formation is used to indicate the average temperature in theformation. Experimental analysis and/or simulation may be used to assessthe weight percentage of saturates as a function of the averagetemperature in the formation. For example, SARA (Saturates, Aromatics,Resins, and Asphaltenes) analysis (sometimes referred to asAsphaltene/Wax/Hydrate Deposition analysis) may be used to assess theweight percentage of saturates in a sample of fluids from the formation.In some formations, the weight percentage of saturates has a linearrelationship to the average temperature in the formation. The relationbetween the weight percentage of saturates and the average temperaturemay then be used in the field to assess the average temperature in theformation by monitoring the weight percentage of saturates in fluidsproduced from the formation. In some embodiments, the pressure in theformation is reduced when the monitored weight percentage of saturatesreaches a selected value. The selected value of the weight percentage ofsaturates may be chosen based on the selected temperature, ortemperature range, in the formation for reducing the pressure in theformation and the relation between the weight percentage of saturatesand the average temperature. In some embodiments, the selected value ofweight percentage of saturates is between about 20% and about 40%,between about 25% and about 35%, or between about 28% and about 32%. Forexample, the selected value may be about 30% by weight saturates.

In some embodiments, weight percentages of n-C₇ in fluids produced fromthe formation is used to indicate the average temperature in theformation. Experimental analysis and/or simulation may be used to assessthe weight percentages of n-C₇ as a function of the average temperaturein the formation. In some formations, the weight percentages of n-C₇ hasa linear relationship to the average temperature in the formation. Therelation between the weight percentages of n-C₇ and the averagetemperature may then be used in the field to assess the averagetemperature in the formation by monitoring the weight percentages ofn-C₇ in fluids produced from the formation. In some embodiments, thepressure in the formation is reduced when the monitored weightpercentage of n-C₇ reaches a selected value. The selected value of theweight percentage of n-C₇ may be chosen based on the selectedtemperature, or temperature range, in the formation for reducing thepressure in the formation and the relation between the weight percentageof n-C₇ and the average temperature. In some embodiments, the selectedvalue of weight percentage of n-C₇ is between about 50% and about 70%,between about 55% and about 65%, or between about 58% and about 62%. Forexample, the selected value may be about 60% by weight n-C₇.

The pressure in the formation may be reduced by producing fluids (forexample, visbroken fluids and/or mobilized fluids) from the formation.In some embodiments, the pressure is reduced below a pressure at whichfluids coke in the formation to inhibit coking at pyrolysistemperatures. For example, the pressure is reduced to a pressure belowabout 1000 kPa, below about 800 kPa, or below about 700 kPa (forexample, about 690 kPa). In certain embodiments, the selected pressureis at least about 100 kPa, at least about 200 kPa, or at least about 300kPa. The pressure may be reduced to inhibit coking of asphaltenes orother high molecular weight hydrocarbons in the formation. In someembodiments, the pressure may be maintained below a pressure at whichwater passes through a liquid phase at downhole (formation) temperaturesto inhibit liquid water and dolomite reactions. After reducing thepressure in the formation, the temperature may be increased to pyrolysistemperatures to begin pyrolyzation and/or upgrading of fluids in theformation. The pyrolyzed and/or upgraded fluids may be produced from theformation.

In certain embodiments, the amount of fluids produced at temperaturesbelow visbreaking temperatures, the amount of fluids produced atvisbreaking temperatures, the amount of fluids produced before reducingthe pressure in the formation, and/or the amount of upgraded orpyrolyzed fluids produced may be varied to control the quality andamount of fluids produced from the formation and the total recovery ofhydrocarbons from the formation. For example, producing more fluidduring the early stages of treatment (for example, producing fluidsbefore reducing the pressure in the formation) may increase the totalrecovery of hydrocarbons from the formation while reducing the overallquality (lowering the overall API gravity) of fluid produced from theformation. The overall quality is reduced because more heavyhydrocarbons are produced by producing more fluids at the lowertemperatures. Producing less fluids at the lower temperatures mayincrease the overall quality of the fluids produced from the formationbut may lower the total recovery of hydrocarbons from the formation. Thetotal recovery may be lower because more coking occurs in the formationwhen less fluids are produced at lower temperatures.

In certain embodiments, the formation is heated using isolated cells ofheaters (cells or sections of the formation that are not interconnectedfor fluid flow). The isolated cells may be created by using largerheater spacings in the formation. For example, large heater spacings maybe used in the embodiments depicted in FIGS. 176-179. These isolatedcells may be produced during early stages of heating (for example, attemperatures below visbreaking temperatures). Because the cells areisolated from other cells in the formation, the pressures in theisolated cells are high and more liquids are producible from theisolated cells. Thus, more liquids may be produced from the formationand a higher total recovery of hydrocarbons may be reached. During laterstages of heating, the heat gradient may interconnect the isolated cellsand pressures in the formation will drop.

In certain embodiments, the heat gradient in the formation is modifiedso that a gas cap is created at or near an upper portion of thehydrocarbon layer. For example, the heat gradient made by heaters 438depicted in the embodiments depicted in FIGS. 176-179 may be modified tocreate the gas cap at or near overburden 482 of hydrocarbon layer 484.The gas cap may push or drive liquids to the bottom of the hydrocarbonlayer so that more liquids may be produced from the formation. In situgeneration of the gas cap may be more efficient than introducingpressurized fluid into the formation. The in situ generated gas capapplies force evenly through the formation with little or no channelingor fingering that may reduce the effectiveness of introduced pressurizedfluid.

In certain embodiments, the number and/or location of production wellsin the formation is varied based on the viscosity of fluid in theformation. The viscosities in the zones may be assessed before placingthe production wells in the formation, before heating the formation,and/or after heating the formation. In some embodiments, more productionwells are located in zones in the formation that have lower viscosities.For example, in certain formations, upper portions, or zones, of theformation may have lower viscosities. In some embodiments, moreproduction wells are located in the upper zones. Producing throughproduction wells in the less viscous zones of the formation may resultin production of higher quality (more upgraded) oil from the formation.

In some embodiments, more production wells are located in zones in theformation that have higher viscosities. Pressure propagation may beslower in the zones with higher viscosities. The slower pressurepropagation may make it more difficult to control pressure in the zoneswith higher viscosities. Thus, more production wells may be located inthe zones with higher viscosities to provide better pressure control inthese zones.

In some embodiments, zones in the formation with different assessedviscosities are heated at different rates. In certain embodiments, zonesin the formation with higher viscosities are heated at higher heatingrates than zones with lower viscosities. Heating the zones with higherviscosities at the higher heating rates mobilizes and/or upgrades thesezones at a faster rate so that these zones may “catch up” in viscosityand/or quality to the slower heated zones.

In some embodiments, the heater spacing is varied to provide differentheating rates to zones in the formation with different assessedviscosities. For example, denser heater spacings (less spaces betweenheaters) may be used in zones with higher viscosities to heat thesezones at higher heating rates. In some embodiments, a production well(for example, a substantially vertical production well) is located inthe zones with denser heater spacings and higher viscosities. Theproduction well may be used to remove fluids from the formation andrelieve pressure from the higher viscosity zones. In some embodiments,one or more substantially vertical openings, or production wells, arelocated in the higher viscosity zones to allow fluids to drain in thehigher viscosity zones. The draining fluids may be produced from theformation through production wells located near the bottom of the higherviscosity zones.

In certain embodiments, production wells are located in more than onezone in the formation. The zones may have different initialpermeabilities. In certain embodiments, a first zone has an initialpermeability of at least about 1 darcy and a second zone has an initialpermeability of at most about 0.1 darcy. In some embodiments, the firstzone has an initial permeability of between about 1 darcy and about 10darcy. In some embodiments, the second zone has an initial permeabilitybetween about 0.01 darcy and 0.1 darcy. The zones may be separated by asubstantially impermeable barrier (with an initial permeability of about10 μdarcy or less). Having the production well located in both zonesallows for fluid communication (permeability) between the zones and/orpressure equalization between the zones.

In some embodiments, openings (for example, substantially verticalopenings) are formed between zones with different initial permeabilitiesthat are separated by a substantially impermeable barrier. Bridging thezones with the openings allows for fluid communication (permeability)between the zones and/or pressure equalization between the zones. Insome embodiments, openings in the formation (such as pressure reliefopenings and/or production wells) allow gases or low viscosity fluids torise in the openings. As the gases or low viscosity fluids rise, thefluids may condense or increase viscosity in the openings so that thefluids drain back down the openings to be further upgraded in theformation. Thus, the openings may act as heat pipes by transferring heatfrom the lower portions to the upper portions where the fluids condense.The wellbores may be packed and sealed near or at the overburden toinhibit transport of formation fluid to the surface.

In some embodiments, production of fluids is continued after reducingand/or turning off heating of the formation. The formation may be heatedfor a selected time. The formation may be heated until it reaches aselected average temperature. Production from the formation may continueafter the selected time. Continuing production may produce more fluidfrom the formation as fluids drain towards the bottom of the formationand/or as fluids are upgraded by passing by hot spots in the formation.In some embodiments, a horizontal production well is located at or nearthe bottom of the formation (or a zone of the formation) to producefluids after heating is turned down and/or off.

In certain embodiments, initially produced fluids (for example, fluidsproduced below visbreaking temperatures), fluids produced at visbreakingtemperatures, and/or other viscous fluids produced from the formationare blended with diluent to produce fluids with lower viscosities. Insome embodiments, the diluent includes upgraded or pyrolyzed fluidsproduced from the formation. In some embodiments, the diluent includesupgraded or pyrolyzed fluids produced from another portion of theformation or another formation. In certain embodiments, the amount offluids produced at temperatures below visbreaking temperatures and/orfluids produced at visbreaking temperatures that are blended withupgraded fluids from the formation is adjusted to create a fluidsuitable for transportation and/or use in a refinery. The amount ofblending may be adjusted so that the fluid has chemical and physicalstability. Maintaining the chemical and physical stability of the fluidmay allow the fluid to be transported, reduce pre-treatment processes ata refinery and/or reduce or eliminate the need for adjusting therefinery process to compensate for the fluid.

In certain embodiments, formation conditions (for example, pressure andtemperature) and/or fluid production are controlled to produce fluidswith selected properties. For example, formation conditions and/or fluidproduction may be controlled to produce fluids with a selected APIgravity and/or a selected viscosity. The selected API gravity and/orselected viscosity may be produced by combining fluids produced atdifferent formation conditions (for example, combining fluids producedat different temperatures during the treatment as described above). Asan example, formation conditions and/or fluid production may becontrolled to produce fluids with an API gravity of about 19° and aviscosity of about 0.35 Pa·s (350 cp) at 5° C.

In certain embodiments, a drive process (for example, a steam injectionprocess such as cyclic steam injection, a steam assisted gravitydrainage process (SAGD), a solvent injection process, a vapor solventand SAGD process, or a carbon dioxide injection process) is used totreat the tar sands formation in addition to the in situ heat treatmentprocess. In some embodiments, heaters are used to create highpermeability zones (or injection zones) in the formation for the driveprocess. Heaters may be used to create a mobilization geometry orproduction network in the formation to allow fluids to flow through theformation during the drive process. For example, heaters may be used tocreate drainage paths between the heaters and production wells for thedrive process. In some embodiments, the heaters are used to provide heatduring the drive process. The amount of heat provided by the heaters maybe small compared to the heat input from the drive process (for example,the heat input from steam injection).

The concentration of components in the formation and/or produced fluidsmay change during an in situ heat treatment process. As theconcentration of the components in the formation and/or produced fluidsand/or hydrocarbons separated from the produced fluid changes due toformation of the components, solubility of the components in theproduced fluids and/or separated hydrocarbons tends to change.Hydrocarbons separated from the produced fluid may be hydrocarbons thathave been treated to remove salty water and/or gases from the producedfluid. For example, the produced fluids and/or separated hydrocarbonsmay contain components that are soluble in the condensable hydrocarbonportion of the produced fluids at the beginning of processing. Asproperties of the hydrocarbons in the produced fluids change (forexample, TAN, asphaltenes, P-value, olefin content, mobilized fluidscontent, visbroken fluids content, pyrolyzed fluids content, orcombinations thereof), the components may tend to become less soluble inthe produced fluids and/or in the hydrocarbon stream separated from theproduced fluids. In some instances, components in the produced fluidsand/or components in the separated hydrocarbons may form two phasesand/or become insoluble. Formation of two phases, through flocculationof asphaltenes, change in concentration of components in the producedfluids, change in concentration of components in separated hydrocarbons,and/or precipitation of components may result in hydrocarbons that donot meet pipeline, transportation, and/or refining specifications.Additionally, the efficiency of the process may be reduced. For example,further treatment of the produced fluids and/or separated hydrocarbonsmay be necessary to produce products with desired properties.

During processing, the P-value of the separated hydrocarbons may bemonitored and the stability of the produced fluids and/or separatedhydrocarbons may be assessed. Typically, a P-value that is at most 1.0indicates that flocculation of asphaltenes from the separatedhydrocarbons generally occurs. If the P-value is initially at least 1.0,and such P-value increases or is relatively stable during heating, thenthis indicates that the separated hydrocarbons are relatively stable.Stability of separated hydrocarbons, as assessed by P-value, may becontrolled by controlling operating conditions in the formation such astemperature, pressure, hydrogen uptake, hydrocarbon feed flow, orcombinations thereof.

In some embodiments, change in API gravity may not occur unless theformation temperature is at least 100° C. For some formations,temperatures of at least 220° C. may be required to produce hydrocarbonsthat meet desired specifications. At increased temperatures cokeformation may occur, even at elevated pressures. As the properties ofthe formation are changed, the P-value of the separated hydrocarbons maydecrease below 1.0 and/or sediment may form, causing the separatedhydrocarbons to become unstable.

In some embodiments, olefins may form during heating of formation fluidsto produce fluids having a reduced viscosity. Separated hydrocarbonsthat include olefins may be unacceptable for processing facilities.Olefins in the separated hydrocarbons may cause fouling and/or cloggingof processing equipment. For example, separated hydrocarbons thatcontains olefins may cause coking of distillation units in a refinery,which results in frequent down time to remove the coked material fromthe distillation units.

During processing, the olefin content of separated hydrocarbons may bemonitored and quality of the separated hydrocarbons assessed. Typically,separated hydrocarbons having a bromine number of 3% and/or a CAPPolefin number of 3% as 1-decene equivalent indicates that olefinproduction is occurring. If the olefin value decreases or is relativelystable during producing, then this indicates that a minimal orsubstantially low amount of olefins are being produced. Olefin content,as assessed by bromine value and/or CAPP olefin number, may becontrolled by controlling operating conditions in the formation such astemperature, pressure, hydrogen uptake, hydrocarbon feed flow, orcombinations thereof.

In some embodiments, the P-value and/or olefin content may be controlledby controlling operating conditions. For example, if the temperatureincreases above 225° C. and the P-value drops below 1.0, the separatedhydrocarbons may become unstable. Alternatively, the bromine numberand/or CAPP olefin number may increase to above 3%. If the temperatureis maintained below 225° C., minimal changes to the hydrocarbonproperties may occur. In certain embodiments, operating conditions areselected, varied, and/or maintained to produce separated hydrocarbonshaving a P-value of at least about 1, at least about 1.1, at least about1.2, or at least about 1.3. In certain embodiments, operating conditionsare selected, varied, and/or maintained to produce separatedhydrocarbons having a bromine number of at most about 3%, at most about2.5%, at most about 2%, or at most about 1.5%. Heating of the formationat controlled operating conditions includes operating at temperaturesbetween about 100° C. and about 260° C., between about 150° C. and about250° C., between about 200° C. and about 240° C., between about 210° C.and about 230° C., or between about 215° C. and about 225° C. Pressuresmay be between about 1000 kPa and about 15000 kPa, between about 2000kPa and about 10000 kPa, or between about 2500 kPa and about 5000 kPa orat or near a fracture pressure of the formation. In certain embodiments,the selected pressure of about 10000 kPa produces separated hydrocarbonshaving properties acceptable for transportation and/or refineries (forexample, viscosity, P-value, API gravity, and/or olefin content withinacceptable ranges).

Examples of produced mixture properties that may be measured and used toassess the separated hydrocarbon portion of the produced mixtureinclude, but are not limited to, liquid hydrocarbon properties such asAPI gravity, viscosity, asphaltene stability (P-value), and olefincontent (bromine number and/or CAPP number). In certain embodiments,operating conditions in the formation are selected, varied, and/ormaintained to produce an API gravity of at least about 15°, at leastabout 17°, at least about 19°, or at least about 20° in the producedmixture. In certain embodiments, operating conditions in the formationare selected, varied, and/or maintained to produce a viscosity (measuredat 1 atm and 5° C.) of at most about 400 cp, at most about 350 cp, atmost about 250 cp, or at most about 100 cp in the produced mixture. Asan example, the initial viscosity of fluid in the formation is aboveabout 1000 cp or, in some cases, above about 1 million cp. In certainembodiments, operating conditions are selected, varied, and/ormaintained to produce an asphaltene stability (P-value) of at leastabout 1, at least about 1.1, at least about 1.2, or at least about 1.3in the produced mixture. In certain embodiments, operating conditionsare selected, varied, and/or maintained to produce a bromine number ofat most about 3%, at most about 2.5%, at most about 2%, or at most about1.5% in the produced mixture.

In certain embodiments, the mixture is produced from one or moreproduction wells located at or near the bottom of the hydrocarbon layerbeing treated. In other embodiments, the mixture is produced from otherlocations in the hydrocarbon layer being treated (for example, from anupper portion of the layer or a middle portion of the layer).

In one embodiment, the formation is heated to 220° C. or 230° C. whilemaintaining the pressure in the formation below 10000 kPa. The separatedhydrocarbon portion of the mixture produced from the formation may haveseveral desirable properties such as, but not limited to, an API gravityof at least 19°, a viscosity of at most 350 cp, a P-value of at least1.1, and a bromine number of at most 2%. Such separated hydrocarbons maybe transportable through a pipeline without adding diluent or blendingthe mixture with another fluid. The mixture may be produced from one ormore production wells located at or near the bottom of the hydrocarbonlayer being treated.

The in situ heat treatment process may provide less heat to theformation (for example, use a wider heater spacing) if the in situ heattreatment process is followed by a drive process. The drive process mayinvolve introducing a hot fluid into the formation to increase theamount of heat provided to the formation. In some embodiments, theheaters of the in situ heat treatment process may be used to pretreatthe formation to establish injectivity for the subsequent drive process.In some embodiments, the in situ heat treatment process creates orproduces the drive fluid in situ. The in situ produced drive fluid maymove through the formation and move mobilized hydrocarbons from oneportion of the formation to another portion of the formation.

FIG. 180 depicts a top view representation of an embodiment forpreheating using heaters before using the drive process (for example, asteam drive process). Injection wells 788 and production wells 206 aresubstantially vertical wells. Heaters 438 are long substantiallyhorizontal heaters positioned so that the heaters pass in the vicinityof injection wells 788. Heaters 438 intersect the vertical well patternsslightly displaced from the vertical wells.

The vertical location of heaters 438 with respect to injection wells 788and production wells 206 depends on, for example, the verticalpermeability of the formation. In formations with at least some verticalpermeability, injected steam will rise to the top of the permeable layerin the formation. In such formations, heaters 438 may be located nearthe bottom of the hydrocarbon layer 484, as shown in FIG. 181. Informations with very low vertical permeabilities, more than onehorizontal heater may be used with the heaters stacked substantiallyvertically or with heaters at varying depths in the hydrocarbon layer(for example, heater patterns as shown in FIGS. 176-179). The verticalspacing between the horizontal heaters in such formations may correspondto the distance between the heaters and the injection wells. Heaters 438are located in the vicinity of injection wells 788 and/or productionwells 206 so that sufficient energy is delivered by the heaters toprovide flow rates for the drive process that are economically viable.The spacing between heaters 438 and injection wells 788 or productionwells 206 may be varied to provide an economically viable drive process.The amount of preheating may also be varied to provide an economicallyviable process.

In some embodiments, the steam injection (or drive) process (forexample, SAGD, cyclic steam soak, or another steam recovery process) isused to treat the formation and produce hydrocarbons from the formation.The steam injection process may recover a low amount of oil in placefrom the formation (for example, less than 20% recovery of oil in placefrom the formation). The in situ heat treatment process may be usedfollowing the steam injection process to increase the recovery of oil inplace from the formation. In certain embodiments, the steam injectionprocess is used until the steam injection process is no longer efficientat removing hydrocarbons from the formation (for example, until thesteam injection process is no longer economically feasible). The in situheat treatment process is used to produce hydrocarbons remaining in theformation after the steam injection process. Using the in situ heattreatment process after the steam injection process may allow recoveryof at least about 25%, at least about 50%, at least about 55%, or atleast about 60% of oil in place in the formation.

In some embodiments, the formation has been at least somewhat heated bythe steam injection process before treating the formation using the insitu heat treatment process. For example, the steam injection processmay heat the formation to an average temperature between about 200° C.and about 250° C., between about 175° C. and about 265° C., or betweenabout 150° C. and about 270° C. In certain embodiments, the heaters areplaced in the formation after the steam injection process is at least50% completed, at least 75% completed, or near 100% completed. Theheaters provide heat for treating the formation using the in situ heattreatment process. In some embodiments, the heaters are already in placein the formation during the steam injection process. In suchembodiments, the heaters may be energized after the steam injectionprocess is completed or when production of hydrocarbons using the steaminjection process is reduced below a desired level. In some embodiments,steam injection wells from the steam injection process are converted toheater wells for the in situ heat treatment process.

Treating the formation with the in situ heat treatment process after thesteam injection process may be more efficient than only treating theformation with the in situ heat treatment process. The steam injectionprocess may provide some energy (heat) to the formation with the steam.Any energy added to the formation during the steam injection processreduces the amount of energy needed to be supplied by heaters for the insitu heat treatment process. Reducing the amount of energy supplied byheaters reduces costs for treating the formation using the in situ heattreatment process.

In certain embodiments, treating the formation using the steam injectionprocess does not treat the formation uniformly. For example, steaminjection may not be uniform throughout the formation. Variations in theproperties of the formation (for example, fluid injectivities,permeabilities, and/or porosities) may result in non-uniform injectionof the steam through the formation. Because of the non-uniform injectionof the steam, the steam may remove hydrocarbons from different portionsof the formation at different rates or with different results. Forexample, some portions of the formation may have little or no steaminjectivity, which inhibits the hydrocarbon production from theseportions. After the steam injection process is completed, the formationmay have portions that have lower amounts of hydrocarbons produced (morehydrocarbons remaining) than other parts of the formation.

FIG. 182 depicts a side view representation of an embodiment of a tarsands formation subsequent to a steam injection process. Injection well788 is used to inject steam into hydrocarbon layer 484 below overburden482. Portion 790 may have little or no steam injectivity and have smallamounts of hydrocarbons or no hydrocarbons at all removed by the steaminjection process. Portions 792 may include portions that have steaminjectivity and measurable amounts of hydrocarbons are removed by thesteam injection process. Thus, portion 790 may have a greater amount ofhydrocarbons remaining than portions 792 following treatment with thesteam injection process. In some embodiments, hydrocarbon layer 484includes two or more portions 790 with more hydrocarbons remaining thanportions 792.

In some embodiments, the portions with more hydrocarbons remaining (suchas portion 790, depicted in FIG. 182) are large portions of theformation. In some embodiments, the amount of hydrocarbons remaining inthese portions is significantly higher than other portions of theformation (such as portions 792). For example, portions 790 may have arecovery of at most about 10% of the oil in place and portions 792 mayhave a recovery of at least about 30% of the oil in place. In someembodiments, portions 790 have a recovery of between about 0% and about10% of the oil in place, between about 0% and about 15% of the oil inplace, or between about 0% and about 20% of the oil in place. Theportions 792 may have a recovery of between about 20% and about 25% ofthe oil in place, between about 20% and about 40% of the oil in place,or between about 20% and about 50% of the oil in place. Coring, loggingtechniques, and/or seismic imaging may be used to assess hydrocarbonsremaining in the formation and assess the location of one or more of thefirst and/or second portions.

In certain embodiments, during the in situ heat treatment process, moreheat is provided to the first portions of the formation that have morehydrocarbons remaining than the second portions with less hydrocarbonsremaining. In some embodiments, heaters are located in the firstportions but not in the second portions. In some embodiments, heatersare located in both the first portions and the second portions but theheaters in the first portions are designed or operated to provide moreheat than the heaters in the second portions. In some embodiments,heaters pass through both first portions and second portions and theheaters are designed or operated to provide more heat in the firstportions than the second portions.

In some embodiments, steam injection is continued during the in situheat treatment process. For example, steam injection may be continuedwhile liquids are being produced from the formation. The steam injectionmay increase the production of liquids from the formation. In certainembodiments, steam injection may be reduced or stopped when gasproduction from the formation begins.

In some embodiments, the formation is treated using the in situ heattreatment process a significant time after the formation has beentreated using the steam injection process. For example, the in situ heattreatment process is used 1 year, 2 years, 3 years, or longer (forexample, 10 years to 20 years) after a formation has been treated usingthe steam injection process. During this dormant period, heat from thesteam injection process may diffuse to cooler parts of the formation andresult in a more uniform preheating of the formation prior to in situheat treatment. The in situ heat treatment process may be used onformations that have been left dormant after the steam injection processtreatment because further hydrocarbon production using the steaminjection process is not possible and/or not economically feasible. Insome embodiments, the formation remains at least somewhat heated fromthe steam injection process even after the significant time.

In certain embodiments, a fluid is injected into the formation (forexample, a drive fluid or an oxidizing fluid) to move hydrocarbonsthrough the formation from a first section to a second section. In someembodiments, the hydrocarbons are moved from the first section to thesecond section through a third section. FIG. 183 depicts a side viewrepresentation of an embodiment using at least three treatment sectionsin a tar sands formation. Hydrocarbon layer 484 may be divide into threeor more treatment sections. In certain embodiments, hydrocarbon layer484 includes three different types of treatment sections: section 794A,section 794B, and section 794C. Section 794C and sections 794A areseparated by sections 794B. Section 794C, sections 794A, and sections794B may be horizontally displaced from each other in the formation. Insome embodiments, one side of section 794C is adjacent to an edge of thetreatment area of the formation or an untreated section of the formationis left on one side of section 794C before the same or a differentpattern is formed on the opposite side of the untreated section.

In certain embodiments, sections 794A and 794C are heated at or near thesame time to similar temperatures (for example, pyrolysis temperatures).Sections 794A and 794C may be heated to mobilize and/or pyrolyzehydrocarbons in the sections. The mobilized and/or pyrolyzedhydrocarbons may be produced (for example, through one or moreproduction wells) from section 794A and/or section 794C. Section 794Bmay be heated to lower temperatures (for example, mobilizationtemperatures). Little or no production of hydrocarbons to the surfacemay take place through section 794B. For example, sections 794A and 794Cmay be heated to average temperatures of about 300° C. while section794B is heated to an average temperature of about 100° C. and noproduction wells are operated in section 794B.

In certain embodiments, heating and producing hydrocarbons from section794C creates fluid injectivity in the section. After fluid injectivityhas been created in section 794C, a fluid such as a drive fluid (forexample, steam, water, or hydrocarbons) and/or an oxidizing fluid (forexample, air, oxygen, enriched air, or other oxidants) may be injectedinto the section. The fluid may be injected through heaters 438, aproduction well, and/or an injection well located in section 794C. Insome embodiments, heaters 438 continue to provide heat while the fluidis being injected. In other embodiments, heaters 438 may be turned downor off before or during fluid injection.

In some embodiments, providing oxidizing fluid such as air to section794C causes oxidation of hydrocarbons in the section. For example, cokedhydrocarbons and/or heated hydrocarbons in section 794C may oxidize ifthe temperature of the hydrocarbons is above an oxidation ignitiontemperature. In some embodiments, treatment of section 794C with theheaters creates coked hydrocarbons with substantially uniform porosityand/or substantially uniform injectivity so that heating of the sectionis controllable when oxidizing fluid is introduced to the section. Theoxidation of hydrocarbons in section 794C will maintain the averagetemperature of the section or increase the average temperature of thesection to higher temperatures (for example, about 400° C. or above).

In some embodiments, injection of the oxidizing fluid is used to heatsection 794C and a second fluid is introduced into the formation afteror with the oxidizing fluid to create drive fluids in the section.During injection of oxidant, excess oxidant and/or oxidation productsmay be removed from section 794C through one or more production wells.After the formation is raised to a desired temperature, a second fluidmay be introduced into section 794C to react with coke and/orhydrocarbons and generate drive fluid (for example, synthesis gas). Insome embodiments, the second fluid includes water and/or steam.Reactions of the second fluid with carbon in the formation may beendothermic reactions that cool the formation. In some embodiments,oxidizing fluid is added with the second fluid so that some heating ofsection 794C occurs simultaneous with the endothermic reactions. In someembodiments, section 794C may be treated in alternating steps of addingoxidant to heat the formation, and then adding second fluid to generatedrive fluids.

The generated drive fluids in section 794C may include steam, carbondioxide, carbon monoxide, hydrogen, methane, and/or pyrolyzedhydrocarbons. The high temperature in section 794C and the generation ofdrive fluid in the section may increase the pressure of the section sothe drive fluids move out of the section into adjacent sections. Theincreased temperature of section 794C may also provide heat to section794B through conductive heat transfer and/or convective heat transferfrom fluid flow (for example, hydrocarbons and/or drive fluid) tosection 794B.

In some embodiments, hydrocarbons (for example, hydrocarbons producedfrom section 794C) are provided as a portion of the drive fluid. Theinjected hydrocarbons may include at least some pyrolyzed hydrocarbonssuch as pyrolyzed hydrocarbons produced from section 794C. In someembodiments, steam or water are provided as a portion of the drivefluid. Steam or water in the drive fluid may be used to controltemperatures in the formation. For example, steam or water may be usedto keep temperatures lower in the formation. In some embodiments, waterinjected as the drive fluid is turned into steam in the formation due tothe higher temperatures in the formation. The conversion of water tosteam may be used to reduce temperatures or maintain lower temperaturesin the formation.

Fluids injected in section 794C may flow towards section 794B, as shownby the arrows in FIG. 183. Fluid movement through the formationtransfers heat convectively through hydrocarbon layer 484 into sections794B and/or 794A. In addition, some heat may transfer conductivelythrough the hydrocarbon layer between the sections.

Low level heating of section 794B mobilizes hydrocarbons in the section.The mobilized hydrocarbons in section 794B may be moved by the injectedfluid through the section towards section 794A, as shown by the arrowsin FIG. 183. Thus, the injected fluid is pushing hydrocarbons fromsection 794C through section 794B to section 794A. Mobilizedhydrocarbons may be upgraded in section 794A due to the highertemperatures in the section. Pyrolyzed hydrocarbons that move intosection 794A may also be further upgraded in the section. The upgradedhydrocarbons may be produced through production wells located in section794A.

In certain embodiments, at least some hydrocarbons in section 794B aremobilized and drained from the section prior to injecting the fluid intothe formation. Some formations may have high oil saturation (forexample, the Grosmont formation has high oil saturation). The high oilsaturation corresponds to low gas permeability in the formation that mayinhibit fluid flow through the formation. Thus, mobilizing and draining(removing) some oil (hydrocarbons) from the formation may create gaspermeability for the injected fluids.

Fluids in hydrocarbon layer 484 may preferentially move horizontallywithin the hydrocarbon layer from the point of injection because tarsands tend to have a larger horizontal permeability than verticalpermeability. The higher horizontal permeability allows the injectedfluid to move hydrocarbons between sections preferentially versus fluidsdraining vertically due to gravity in the formation. Providingsufficient fluid pressure with the injected fluid may ensure that fluidsare moved to section 794A for upgrading and/or production.

In certain embodiments, section 794B has a larger volume than section794A and/or section 794C. Section 794B may be larger in volume than theother sections so that more hydrocarbons are produced for less energyinput into the formation. Because less heat is provided to section 794B(the section is heated to lower temperatures), having a larger volume insection 794B reduces the total energy input to the formation per unitvolume. The desired volume of section 794B may depend on factors suchas, but not limited to, viscosity, oil saturation, and permeability. Inaddition, the degree of coking is much less in section 794B due to thelower temperature so less hydrocarbons are coked in the formation whensection 794B has a larger volume. In some embodiments, the lower degreeof heating in section 794B allows for cheaper capital costs as lowertemperature materials (cheaper materials) may be used for heaters usedin section 794B.

In some embodiments, karsted formations or karsted layers in formationshave vugs in one or more layers of the formations. The vugs may befilled with viscous fluids such as bitumen or heavy oil. In someembodiments, the karsted layers have a porosity of at least about 20porosity units, at least about 30 porosity units, or at least about 35porosity units. The karsted formation may have a porosity of at mostabout 15 porosity units, at most about 10 porosity units, or at mostabout 5 porosity units. Vugs filled with viscous fluids may inhibitsteam or other fluids from being injected into the formation or thelayers. In certain embodiments, the karsted formation or karsted layersof the formation are treated using the in situ heat treatment process.

Heating of these formations or layers may decrease the viscosity of theviscous fluids in the vugs and allow the fluids to drain (for example,mobilize the fluids). Formations with karsted layers may have sufficientpermeability so that when the viscosity of fluids (hydrocarbons) in theformation is reduced, the fluids drain and/or move through the formationrelatively easily (for example, without a need for creating higherpermeability in the formation).

In some embodiments, the relative amount (the degree) of karst in theformation is assessed using techniques known in the art (for example, 3Dseismic imaging of the formation). The assessment may give a profile ofthe formation showing layers or portions with varying amounts of karstin the formation. In certain embodiments, more heat is provided toselected karsted portions of the formation than other karsted portionsof the formation. In some embodiments, selective amounts of heat areprovided to portions of the formation as a function of the degree ofkarst in the portions. Amounts of heat may be provided by varying thenumber and/or density of heaters in the portions with varying degrees ofkarst.

In certain embodiments, the hydrocarbon fluids in karsted portions havehigher viscosities than hydrocarbons in other non-karsted portions ofthe formation. Thus, more heat may be provided to the karsted portionsto reduce the viscosity of the hydrocarbons in the karsted portions.

In certain embodiments, only the karsted layers of the formation aretreated using the in situ heat treatment process. Other non-karstedlayers of the formation may be used as seals for the in situ heattreatment process. For example, karsted layers with different quantitiesof hydrocarbons in the layers may be treated while other layers are usedas natural seals for the treatment process. In some embodiments, karstedlayers with low quantities of hydrocarbons as compared to the otherkarsted and/or non-karsted layers are used as seals for the treatmentprocess. The quantity of hydrocarbons in the Karsted layer may bedetermined using logging methods and/or Dean Stark distillation methods.The quantity of hydrocarbons may be reported as a volume percent ofhydrocarbons per volume percent of rock, or as volume of hydrocarbonsper mass of rock.

In some embodiments, karsted layers with fewer hydrocarbons are treatedalong with karsted layers with more hydrocarbons. In some embodiments,karsted layers with fewer hydrocarbons are above and below a karstedlayer with more hydrocarbons (the middle karsted layer). Less heat maybe provided to the upper and lower karsted layers than the middlekarsted layer. Less heat may be provided in the upper and lower karstedlayers by having greater heat spacing and/or less heaters in the upperand lower karsted layers as compared to the middle karsted layer. Insome embodiments, less heating of the upper and lower karsted layersincludes heating the layers to mobilization and/or visbreakingtemperatures, but not to pyrolysis temperatures. In some embodiments,the upper and/or lower karsted layers are heated with heaters and theresidual heat from the upper and/or lower layers transfers to the middlelayer.

One or more production wells may be located in the middle karsted layer.Mobilized and/or visbroken hydrocarbons from the upper karsted layer maydrain to the production wells in the middle karsted layer. Heat providedto the lower karsted layer may create a thermal expansion drive and/or agas pressure drive in the lower karsted layer. The thermal expansionand/or gas pressure may drive fluids from the lower karsted layer to themiddle karsted layer. These fluids may be produced through theproduction wells in the middle karsted layer. Providing some heat to theupper and lower karsted layers may increase the total recovery of fluidsfrom the formation by, for example, 25% or more.

In some embodiments, the karsted layers with fewer hydrocarbons arefurther heated to pyrolysis temperatures after production from thekarsted layer with more hydrocarbons is completed or almost completed.The karsted layers with fewer hydrocarbons may also be further treatedby producing fluids through production wells located in the layers.

In some embodiments, a drive process, a solvent injection process and/ora pressurizing fluid process is used after the in situ heat treatment ofthe karsted formation or karsted layers. A drive process may includeinjection of a drive fluid such as steam. A drive process includes, butis not limited to, a steam injection process such as cyclic steaminjection, a steam assisted gravity drainage process (SAGD), and a vaporsolvent and SAGD process. A drive process may drive fluids from oneportion of the formation towards a production well.

A solvent injection process may include injection of a solvating fluid.A solvating fluid includes, but is not limited to, water, emulsifiedwater, hydrocarbons, surfactants, alkaline water solutions (for example,sodium carbonate solutions), caustic, polymers, carbon disulfide, carbondioxide, or mixtures thereof. The solvation fluid may mix with, solvateand/or dilute the hydrocarbons to form a mixture of condensablehydrocarbons and solvation fluids. The mixture may have a reducedviscosity as compared to the initial viscosity of the fluids in theformation. The mixture may flow and/or be mobilized towards productionwells in the formation.

A pressurizing process may include moving hydrocarbons in the formationby injection of a pressurized fluid. The pressurizing fluid may include,but is not limited to, carbon dioxide, nitrogen, steam, methane, and/ormixtures thereof.

In some embodiments, the drive process (for example, the steam injectionprocess) is used to mobilize fluids before the in situ heat treatmentprocess. Steam injection may be used to get hydrocarbons (oil) away fromrock or other strata in the formation. The steam injection may mobilizethe hydrocarbons without significantly heating the rock.

In some embodiments, fluid injected in the formation (for example, steamand/or carbon dioxide) may absorb heat from the formation and cool theformation depending on the pressure in the formation and the temperatureof the injected fluid. In some embodiments, the injected fluid is usedto recover heat from the formation. The recovered heat may be used insurface processing fluids and/or to preheat other portions of theformation using the drive process.

In some embodiments, heaters are used to preheat the karsted formationor karsted layers to create injectivity in the formation. In situ heattreatment of karsted formations and/or karsted layers may allow fordrive fluid injection, solvent injection and/or pressurizing fluidinjection where it was previously unfavorable or unmanageable.Typically, karsted formations were unfavorable for drive processesbecause channeling of the fluid injected in the formation inhibitedpressure build-up in the formation. In situ heat treatment of karstedformations may allow for injection of a drive fluid, a solvent and/or apressurizing fluid by reducing the viscosity of hydrocarbons in theformation and allowing pressure to build in the formations withoutsignificant bypass of the fluid through channels in the formations. Forexample, heating a section of the formation using in situ heat treatmentmay heat and mobilize heavy hydrocarbons (bitumen) by reducing theviscosity of the heavy hydrocarbons in the karsted layer. Some of theheated less viscous heavy hydrocarbons may flow from the karsted layerinto other portions of the formation that are cooler than the heatedkarsted portion. The heated less viscous heavy hydrocarbons may flowthrough channels and/or fractures. The heated heavy hydrocarbons maycool and solidify in the channels, thus creating a temporary seal forthe drive fluid, solvent, and/or pressurizing fluid.

In certain embodiments, the karsted formation or karsted layers areheated to temperatures below the decomposition temperature of mineralsin the formation (for example, rock minerals such as dolomite and/orclay minerals such as kaolinite, illite, or smectite). In someembodiments, the karsted formation or karsted layers are heated totemperatures of at most 400° C., at most 450° C., or at most 500° C.(for example, to a temperature below a dolomite decompositiontemperature at formation pressure). In some embodiments, the karstedformation or karsted layers are heated to temperatures below adecomposition temperature of clay minerals (such as kaolinite) atformation pressure.

In some embodiments, heat is preferentially provided to portions of theformation with low weight percentages of clay minerals (for example,kaolinite) as compared to the content of clay in other portions of theformation. For example, more heat may be provided to portions of theformation with at most 1% by weight clay minerals, at most 2% by weightclay minerals, or at most 3% by weight clay minerals than portions ofthe formation with higher weight percentages of clay minerals. In someembodiments, the rock and/or clay mineral distribution is assessed inthe formation prior to designing a heater pattern and installing theheaters. The heaters may be arranged to preferentially provide heat tothe portions of the formation that have been assessed to have lowerweight percentages of clay minerals as compared to other portions of theformation. In certain embodiments, the heaters are placed substantiallyhorizontally in layers with low weight percentages of clay minerals.

Providing heat to portions of the formation with low weight percentagesof clay minerals may minimize changes in the chemical structure of theclays. For example, heating clays to high temperatures may drive waterfrom the clays and change the structure of the clays. The change instructure of the clay may adversely affect the porosity and/orpermeability of the formation. If the clays are heated in the presenceof air, the clays may oxidize and the porosity and/or permeability ofthe formation may be adversely affected. Portions of the formation witha high weight percentage of clay minerals may be inhibited from reachingtemperatures above temperatures that effect the chemical composition ofthe clay minerals at formation pressures. For example, portions of theformation with large amounts of kaolinite relative to other portions ofthe formation may be inhibited from reaching temperatures above 240° C.In some embodiments, portions of the formation with a high quantity ofclay minerals relative to other portions of the formation may beinhibited from reaching temperatures above 200° C., above 220° C., above240° C., or above 300° C.

In some embodiments, karsted formations may include water. Minerals (forexample, carbonate minerals) in the formation may at least partiallydissociate in the water to form carbonic acid. The concentration ofcarbonic acid in the water may be sufficient to make the water acidic.At pressure greater than ambient formation pressures, dissolution ofminerals in the water may be enhanced, thus formation of acidic water isenhanced. Acidic water may react with other minerals in the formationsuch as dolomite (MgCa(CO₃)₂) and increase the solubility of theminerals. Water at lower pressures, or non-acidic water, may notsolubilize the minerals in the formation. Dissolution of the minerals inthe formation may form fractures in the formation. Thus, controlling thepressure and/or the acidity of water in the formation may control thesolubilization of minerals in the formation. In some embodiments, otherinorganic acids in the formation enhance the solubilization of mineralssuch as dolomite.

In some embodiments, the karsted formation or karsted layers are heatedto temperatures above the decomposition temperature of minerals in theformation. At temperatures above the minerals decomposition temperature,the minerals may decompose to produce carbon dioxide or other products.The decomposition of the minerals and the carbon dioxide production maycreate permeability in the formation and mobilize viscous fluids in theformation. In some embodiments, the produced carbon dioxide ismaintained in the formation to generate a gas cap in the formation. Thecarbon dioxide may be allowed to rise to the upper portions of thekarsted layers to generate the gas cap.

In some embodiments, the production front of the drive process followsbehind the heat front of the in situ heat treatment process. In someembodiments, areas behind the production front are further heated toproduce more fluids from the formation. Further heating behind theproduction front may also maintain the gas cap behind the productionfront and/or maintain quality in the production front of the driveprocess.

In certain embodiments, the drive process is used before the in situheat treatment of the formation. In some embodiments, the drive processis used to mobilize fluids in a first section of the formation. Themobilized fluids may then be pushed into a second section by heating thefirst section with heaters. Fluids may be produced from the secondsection. In some embodiments, the fluids in the second section arepyrolyzed and/or upgraded using the heaters.

In formations with low permeabilities, the drive process may be used tocreate a “gas cushion” or pressure sink before the in situ heattreatment process. The gas cushion may inhibit pressures from increasingquickly to fracture pressure during the in situ heat treatment process.The gas cushion may provide a path for gases to escape or travel duringearly stages of heating during the in situ heat treatment process.

In some embodiments, the drive process (for example, the steam injectionprocess) is used to mobilize fluids before the in situ heat treatmentprocess. Steam injection may be used to get hydrocarbons (oil) away fromrock or other strata in the formation. The steam injection may mobilizethe oil without significantly heating the rock.

In some embodiments, injection of a fluid (for example, steam or carbondioxide) may consume heat in the formation and cool the formationdepending on the pressure in the formation. In some embodiments, theinjected fluid is used to recover heat from the formation. The recoveredheat may be used in surface processing fluids and/or to preheat otherportions of the formation using the drive process.

FIG. 184 depicts a representation of an embodiment for producinghydrocarbons from a hydrocarbon containing formation (for example, a tarsands formation). Hydrocarbon layer 484 includes one or more portionswith heavy hydrocarbons. Hydrocarbons may be produced from hydrocarbonlayer 484 using more than one process. In certain embodiments,hydrocarbons are produced from a first portion of hydrocarbon layer 484using a steam injection process (for example, cyclic steam injection orsteam assisted gravity drainage) and a second portion of the hydrocarbonlayer using an in situ heat treatment process. In the steam injectionprocess, steam is injected into the first portion of hydrocarbon layer484 through injection well 788. First hydrocarbons are produced from thefirst portion through production well 206A. The first hydrocarbonsinclude hydrocarbons mobilized by the injection of steam. In certainembodiments, the first hydrocarbons have an API gravity of at most 15°,at most 10°, at most 8°, or at most 6°.

Heaters 438 are used to heat the second portion of hydrocarbon layer 484to mobilization, visbreaking, and/or pyrolysis temperatures. Secondhydrocarbons are produced from the second portion through productionwell 206B. In some embodiments, the second hydrocarbons include at leastsome pyrolyzed hydrocarbons. In certain embodiments, the secondhydrocarbons have an API gravity of at least 15°, at least 20°, or atleast 25°.

In some embodiments, the first portion of hydrocarbon layer 484 istreated using heaters after the steam injection process. Heaters may beused to increase the temperature of the first portion and/or treat thefirst portion using an in situ heat treatment process. Secondhydrocarbons (including at least some pyrolyzed hydrocarbons) may beproduced from the first portion through production well 206A.

In some embodiments, the second portion of hydrocarbon layer 484 istreated using the steam injection process before using heaters 438 totreat the second portion. The steam injection process may be used toproduce some fluids (for example, first hydrocarbons or hydrocarbonsmobilized by the steam injection) through production well 206B from thesecond portion and/or preheat the second portion before using heaters438. In some embodiments, the steam injection process may be used afterusing heaters 438 to treat the first portion and/or the second portion.

Producing hydrocarbons through both processes increases the totalrecovery of hydrocarbons from hydrocarbon layer 484 and may be moreeconomical than using either process alone. In some embodiments, thefirst portion is treated with the in situ heat treatment process afterthe steam injection process is completed. For example, after the steaminjection process no longer produces viable amounts of hydrocarbon fromthe first portion, the in situ heat treatment process may be used on thefirst portion.

Steam is provided to injection well 788 from facility 796. Facility 796is a steam and electricity cogeneration facility. Facility 796 may burnhydrocarbons in generators to make electricity. Facility 796 may burngaseous and/or liquid hydrocarbons to make electricity. The electricitygenerated is used to provide electrical power for heaters 438. Wasteheat from the generators is used to make steam. In some embodiments,some of the hydrocarbons produced from the formation are used to providegas for heaters 438, if the heaters utilize gas to provide heat to theformation. The amount of electricity and steam generated by facility 796may be controlled to vary the production rate and/or quality ofhydrocarbons produced from the first portion and/or the second portionof hydrocarbon layer 484. The production rate and/or quality ofhydrocarbons produced from the first portion and/or the second portionmay be varied to produce a selected API gravity in a mixture made byblending the first hydrocarbons with the second hydrocarbons. The firsthydrocarbon and the second hydrocarbons may be blended after productionto produce the selected API gravity. The production from the firstportion and/or the second portion may be varied in response to changesin the marketplace for either first hydrocarbons, second hydrocarbons,and/or a mixture of the first and second hydrocarbons.

First hydrocarbons produced from production well 206A and/or secondhydrocarbons produced from production well 206B may be used as fuel forfacility 796. In some embodiments, first hydrocarbons and/or secondhydrocarbons are treated (for example, removing undesirable products)before being used as fuel for facility 796. In some embodiments, coke orother hydrocarbon residue produced or removed from the formation (forexample, mined from the formation) may provide fuel for facility 796.The hydrocarbon residue may be gasified or burned in a residue burningfacility before providing the hydrocarbons to facility 796. The residueburning facility may produce hydrocarbon gases (such as natural gas)and/or other products (such as carbon dioxide or syngas products(synthesis gas products)). The carbon dioxide may be sequestered in theformation after treatment of the formation.

The amount of first hydrocarbons and second hydrocarbons used as fuelfor facility 796 may be determined, for example, by economics for theoverall process, the marketplace for either first or secondhydrocarbons, availability of treatment facilities for either first orsecond hydrocarbons, and/or transportation facilities available foreither first or second hydrocarbons. In some embodiments, most or allthe hydrocarbon gas produced from hydrocarbon layer 484 is used as fuelfor facility 796. Burning all the hydrocarbon gas in facility 796eliminates the need for treatment and/or transportation of gasesproduced from hydrocarbon layer 484.

The produced first hydrocarbons and the second hydrocarbons may betreated and/or blended in facility 798. In some embodiments, the firstand second hydrocarbons are blended to make a mixture that istransportable through a pipeline. In some embodiments, the first andsecond hydrocarbons are blended to make a mixture that is useable as afeedstock for a refinery. The amount of first and second hydrocarbonsproduced may be varied based on changes in the requirements fortreatment and/or blending of the hydrocarbons. In some embodiments,treated hydrocarbons are used in facility 796.

In some embodiments, the steam injection process and the in situ heattreatment process (for example, the in situ conversion process) are usedsynergistically in different layers (for example, vertically displacedlayers) in the formation. For example, in a karsted formation, differentzones or layers in the formation may have different oil saturations,water saturations, porosities, and/or permeabilities. Some layers mayhave good steam injectivities while others have near zero steaminjectivity. The steam injectivity may depend on the water saturation ofthe zone and the permeability. Thus, varying the use of the steaminjection process and the in situ heat treatment process in these layersmay be economically advantageous by, for example, producing morehydrocarbons with less energy input into the formation. The steaminjection process may include steam drive, cyclic steam injection, SAGD,or other process of steam injection into the formation.

FIG. 185 depicts a representation of an embodiment for producinghydrocarbons from multiple layers in a tar sands formation. Hydrocarbonlayers 484A,B,C include one or more portions with heavy hydrocarbons.Hydrocarbon layers 484A,B,C may have different oil saturations, watersaturations, porosities, and/or permeabilities. In one embodiment,hydrocarbon layers 484A,C have lower oil saturations, higher watersaturations, and lower porosities than hydrocarbon layer 484B. The steaminjection process may be used in hydrocarbon layers 484A,C usinginjection wells 788A,C and production wells 206A,C. The in situ heattreatment process may be used in hydrocarbon layer 484B using heaters438 and production well 206B. Hydrocarbon layer 484B may have high oilsaturation and low steam injectivity. After in situ heat treatment ofhydrocarbon layer 484B, the layer may have steam injectivity.Hydrocarbon layer 484B may be treated using the steam injection processfor a selected time (for example, one year, two years, three years, orlonger).

Injecting steam into hydrocarbon layers 484A,C above and belowhydrocarbon layer 484B may increase the efficiency of producinghydrocarbons from the formation. Steam injection in hydrocarbon layers484A,C lowers the viscosity and increases the pressures in these layersso that hydrocarbons move into hydrocarbon layer 484B. Heat fromhydrocarbon layer 484B may conduct and/or convect into hydrocarbonlayers 484A,C and preheat these layers to lower the oil viscosity and/orincrease the steam injectivity in hydrocarbon layers 484A,C.Additionally, some steam may rise from hydrocarbon layer 484C intohydrocarbon layer 484B. This steam may provide additional heat andincreased mobilization in hydrocarbon layer 484B. The steam injectionprocess and/or the in situ heat treatment process may be used (forexample, varied) as described above for the embodiment depicted in FIG.184. Hydrocarbons produced from any of hydrocarbon layers 484A,B,C maybe used and/or processed in facility 796 and/or facility 798, asdescribed above for the embodiment depicted in FIG. 184.

In some embodiments, impermeable shale layers exist between hydrocarbonlayer 484B and hydrocarbon layers 484A,C. Using the in situ heattreatment process on hydrocarbon layer 484B may desiccate the shalelayers and increase the permeability of the shale layers to allow fluidto flow through the shale layers. The increased permeability in theshale layers allows mobilized hydrocarbons to flow from hydrocarbonlayer 484A into hydrocarbon layer 484B. These hydrocarbons may beupgraded and produced in hydrocarbon layer 484B.

FIG. 186 depicts an embodiment for heating and producing from theformation with the temperature limited heater in a production wellbore.Production conduit 800 is located in wellbore 742. In certainembodiments, a portion of wellbore 742 is located substantiallyhorizontally in formation 524. In some embodiments, the wellbore islocated substantially vertically in the formation. In an embodiment, atleast a portion of wellbore 742 is an open wellbore (an uncasedwellbore). In some embodiments, the wellbore has a casing or liner withperforations or openings to allow fluid to flow into the wellbore.

Conduit 800 may be made from carbon steel or more corrosion resistantmaterials such as stainless steel. Conduit 800 may include apparatus andmechanisms for gas lifting or pumping produced oil to the surface. Forexample, conduit 800 includes gas lift valves used in a gas liftprocess. Examples of gas lift control systems and valves are disclosedin U.S. Pat. Nos. 6,715,550 to Vinegar et al. and 7,259,688 to Hirsch etal., and U.S. Patent Application Publication No. 2002-0036085 to Bass etal., each of which is incorporated by reference as if fully set forthherein. Conduit 800 may include one or more openings (perforations) toallow fluid to flow into the production conduit. In certain embodiments,the openings in conduit 800 are in a portion of the conduit that remainsbelow the liquid level in wellbore 742. For example, the openings are ina horizontal portion of conduit 800.

Heater 802 is located in conduit 800. In some embodiments, heater 802 islocated outside conduit 800, as shown in FIG. 187. The heater locatedoutside the production conduit may be coupled (strapped) to theproduction conduit. In some embodiments, more than one heater (forexample, two, three, or four heaters) are placed about conduit 800. Theuse of more than one heater may reduce bowing or flexing of theproduction conduit caused by heating on only one side of the productionconduit. In an embodiment, heater 802 is a temperature limited heater.Heater 802 provides heat to reduce the viscosity of fluid (such as oilor hydrocarbons) in and near wellbore 742. In certain embodiments,heater 802 raises the temperature of the fluid in wellbore 742 up to atemperature of 250° C. or less (for example, 225° C., 200° C., or 150°C.). Heater 802 may be at higher temperatures (for example, 275° C.,300° C., or 325° C.) because the heater provides heat to conduit 800 andthere is some temperature differential between the heater and theconduit. Thus, heat produced from the heater does not raise thetemperature of fluids in the wellbore above 250° C.

In certain embodiments, heater 802 includes ferromagnetic materials suchas Carpenter Temperature Compensator “32”, Alloy 42-6, Alloy 52, Invar36, or other iron-nickel or iron-nickel-chromium alloys. In certainembodiments, nickel or nickel-chromium alloys are used in heater 802. Insome embodiments, heater 802 includes a composite conductor with a morehighly conductive material such as copper on the inside of the heater toimprove the turndown ratio of the heater. Heat from heater 802 heatsfluids in or near wellbore 742 to reduce the viscosity of the fluids andincrease a production rate through conduit 800.

In certain embodiments, portions of heater 802 above the liquid level inwellbore 742 (such as the vertical portion of the wellbore depicted inFIGS. 186 and 187) have a lower maximum temperature than portions of theheater located below the liquid level. For example, portions of heater802 above the liquid level in wellbore 742 may have a maximumtemperature of 100° C. while portions of the heater located below theliquid level have a maximum temperature of 250° C. In certainembodiments, such a heater includes two or more ferromagnetic sectionswith different Curie temperatures and/or phase transformationtemperature ranges to achieve the desired heating pattern. Providingless heat to portions of wellbore 742 above the liquid level and closerto the surface may save energy.

In certain embodiments, heater 802 is electrically isolated on theoutside surface of the heater and allowed to move freely in conduit 800.In some embodiments, electrically insulating centralizers are placed onthe outside of heater 802 to maintain a gap between conduit 800 and theheater.

In some embodiments, heater 802 is cycled (turned on and off) so thatfluids produced through conduit 800 are not overheated. In anembodiment, heater 802 is turned on for a specified amount of time untila temperature of fluids in or near wellbore 742 reaches a desiredtemperature (for example, the maximum temperature of the heater). Duringthe heating time (for example, 10 days, 20 days, or 30 days), productionthrough conduit 800 may be stopped to allow fluids in the formation to“soak” and obtain a reduced viscosity. After heating is turned off orreduced, production through conduit 800 is started and fluids from theformation are produced without excess heat being provided to the fluids.During production, fluids in or near wellbore 742 will cool down withoutheat from heater 802 being provided. When the fluids reach a temperatureat which production significantly slows down, production is stopped andheater 802 is turned back on to reheat the fluids. This process may berepeated until a desired amount of production is reached. In someembodiments, some heat at a lower temperature is provided to maintain aflow of the produced fluids. For example, low temperature heat (forexample, 100° C., 125° C., or 150° C.) may be provided in the upperportions of wellbore 742 to keep fluids from cooling to a lowertemperature.

In some embodiments, a temperature limited heater positioned in awellbore heats steam that is provided to the wellbore. The heated steammay be introduced into a portion of the formation. In certainembodiments, the heated steam may be used as a heat transfer fluid toheat a portion of the formation. In some embodiments, the steam is usedto solution mine desired minerals from the formation. In someembodiments, the temperature limited heater positioned in the wellboreheats liquid water that is introduced into a portion of the formation.

In an embodiment, the temperature limited heater includes ferromagneticmaterial with a selected Curie temperature and/or a selected phasetransformation temperature range. The use of a temperature limitedheater may inhibit a temperature of the heater from increasing beyond amaximum selected temperature (for example, a temperature at or about theCurie temperature and/or the phase transformation temperature range).Limiting the temperature of the heater may inhibit potential burnout ofthe heater. The maximum selected temperature may be a temperatureselected to heat the steam to above or near 100% saturation conditions,superheated conditions, or supercritical conditions. Using a temperaturelimited heater to heat the steam may inhibit overheating of the steam inthe wellbore. Steam introduced into a formation may be used forsynthesis gas production, to heat the hydrocarbon containing formation,to carry chemicals into the formation, to extract chemicals or mineralsfrom the formation, and/or to control heating of the formation.

A portion of the formation where steam is introduced or that is heatedwith steam may be at significant depths below the surface (for example,greater than about 1000 m, about 2500 m, or about 5000 m below thesurface). If steam is heated at the surface of the formation andintroduced to the formation through a wellbore, a quality of the heatedsteam provided to the wellbore at the surface may have to be relativelyhigh to accommodate heat losses to the wellbore casing and/or theoverburden as the steam travels down the wellbore. Heating the steam inthe wellbore may allow the quality of the steam to be significantlyimproved before the steam is provided to the formation. A temperaturelimited heater positioned in a lower section of the overburden and/oradjacent to a target zone of the formation may be used to controllablyheat steam to improve the quality of the steam injected into theformation and/or inhibit condensation along the length of the heater. Incertain embodiments, the temperature limited heater improves the qualityof the steam injected and/or inhibits condensation in the wellbore forlong steam injection wellbores (especially for long horizontal steaminjection wellbores).

A temperature limited heater positioned in a wellbore may be used toheat the steam to above or near 100% saturation conditions orsuperheated conditions. In some embodiments, a temperature limitedheater may heat the steam so that the steam is above or nearsupercritical conditions. The static head of fluid above the temperaturelimited heater may facilitate producing 100% saturation, superheated,and/or supercritical conditions in the steam. Supercritical or nearsupercritical steam may be used to strip hydrocarbon material and/orother materials from the formation. In certain embodiments, steamintroduced into the formation may have a high density (for example, aspecific gravity of about 0.8 or above). Increasing the density of thesteam may improve the ability of the steam to strip hydrocarbon materialand/or other materials from the formation.

In some embodiments, the tar sands formation may be treated by the insitu heat treatment process to produce pyrolyzed product from theformation. A significant amount of carbon in the form of coke may remainin tar sands formation when production of pyrolysis product from theformation is complete. In some embodiments, the coke in the formationmay be utilized to produce heat and/or additional products from theheated coke containing portions of the formation.

In some embodiments, air, oxygen enriched air, and/or other oxidants maybe introduced into the treatment area that has been pyrolyzed to reactwith the coke in the treatment area. The temperature of the treatmentarea may be sufficiently hot to support burning of the coke withoutadditional energy input from heaters. The oxidation of the coke maysignificantly heat the portion of the formation. Some of the heat maytransfer to portions of the formation adjacent to the treatment area.The transferred heat may mobilize fluids in portions of the formationadjacent to the treatment area. The mobilized fluids may flow into andbe produced from production wells near the perimeter of the treatmentarea.

Gases produced from the formation heated by combusting coke in theformation may be at high temperature. The hot gases may be utilized inan energy recovery cycle (for example, a Kalina cycle or a Rankinecycle) to produce electricity.

The air, oxygen enriched air and/or other oxidants may be introducedinto the formation for a sufficiently long period of time to heat aportion of the treatment area to a desired temperature sufficient toallow for the production of synthesis gas of a desired composition. Thetemperature may be from 500° C. to about 1000° C. or higher. When thetemperature of the portion is at or near the desired temperature, asynthesis gas generating fluid, such as water, may be introduced intothe formation to result in the formation of synthesis gas. Synthesis gasproduced from the formation may be sent to a treatment facility and/orbe sent through a pipeline to a desired location. During introduction ofthe synthesis gas generating fluid, the introduction of air, oxygenenriched air, and/or other oxidants may be stopped, reduced, ormaintained. If the temperature of the formation reduces so that thesynthesis gas produced from the formation does not have the desiredcomposition, introduction of the syntheses gas generating fluid may bestopped or reduced, and the introduction of air, enriched air and/orother oxidants may be started or increased so that oxidation of coke inthe formation reheats portions of the treatment area. The introductionof oxidant to heat the formation and the introduction of synthesis gasgenerating fluid to produce synthesis gas may be cycled until all or asignificant portion of the treatment area is treated.

In certain embodiments, a subsurface formation is treated in stages. Thetreatment may be initiated with electrical heating with further heatinggenerated from oxidation of hydrocarbons and hot gas production from theformation. Hydrocarbons (e.g., heavy hydrocarbons and/or bitumen) may bemoved from one portion of the formation to another where thehydrocarbons are produced from the formation. By using a combination ofheaters, oxidizing fluid and/or drive fluid, the overall time necessaryto initiate production from a formation may be decreased relative totimes necessary to initiate production using heaters and/or driveprocesses alone. By controlling a rate of oxidizing fluid injectionand/or drive fluid injection in conjunction with heating with heaters, arelatively uniform temperature distribution may be obtained in sections(portions) of the subsurface formation.

A method for treating a hydrocarbon containing formation with heaters incombination with an oxidizing fluid may include providing heat to afirst portion of the formation from a plurality of heaters located inheater wells in the first portion. Fluids may be produced through one ormore production wells in a second portion of the formation that issubstantially adjacent to the first portion. The heat provided to thefirst portion may be reduced or turned off after a selected time. Anoxidizing fluid may be provided through one or more of the heater wellsin the first portion. Heat may be provided to the first portion and thesecond portion through oxidation of at least some hydrocarbons in thefirst portion. Fluids may be produced through at least one of theproduction wells in the second portion. The fluids may include at leastsome oxidized hydrocarbons. Transportation fuel may be produced from thehydrocarbons produced from the first and/or second of the formation.

FIG. 188 depicts a schematic of an embodiment of a first stage oftreating the tar sands formation with electrical heaters. Hydrocarbonlayer 484 may be separated into section 794A and section 794B. Heaters438 may be located in section 794A. Production wells 206 may be locatedin section 794B. In some embodiments, production wells 206 extend intosection 794A.

Heaters 438 may be used to heat and treat portions of section 794Athrough conductive, convective, and/or radiative heat transfer. Forexample, heaters 438 may mobilize, visbreak, and/or pyrolyzehydrocarbons in section 794A. Production wells 206 may be used toproduce mobilized, visbroken, and/or pyrolyzed hydrocarbons from section794A.

FIG. 189 depicts a schematic of an embodiment of a second stage oftreating the tar sands formation with fluid injection and oxidation.After at least some hydrocarbons from section 794A have been produced(for example, a majority of hydrocarbons in the section or almost allproducible hydrocarbons in the section), the heater wells in section794A may be converted to injection wells 788. In some embodiments, theheater wells are open wellbores below the overburden. In someembodiments, the heater wells are initially installed into wellboresthat include perforated casings. In some embodiments, the heater wellsare perforated using perforation guns after heating from the heaterwells is completed.

Injection wells 788 may be used to inject an oxidizing fluid (forexample, air, oxygen, enriched air, or other oxidants) into theformation. In some embodiments, the oxidation includes liquid waterand/or steam. The amount of oxidizing fluid may be controlled to adjustsubsurface combustion patterns. In some embodiments, carbon dioxide orother fluids are injected into the formation to controlheating/production in the formation. The oxidizing fluid may oxidize(combust) or otherwise react with hydrocarbons remaining in theformation (for example, coke). Water in the oxidizing fluid may reactwith coke and/or hydrocarbons in the hot formation to produce syngas inthe formation. Production wells 206 in section 794B may be converted toheater/gas production wells 804. Heater/gas production wells 804 may beused to produce oxidation gases and/or syngas products from theformation. Producing the hot oxidation gases and/or syngas throughheater/gas production wells 804 in section 794B may heat the section tohigher temperatures so that hydrocarbons in the section are mobilized,visbroken, and/or pyrolyzed in the section. Production wells 206 insection 794C may be used to produce mobilized, visbroken, and/orpyrolyzed hydrocarbons from section 794B.

In certain embodiments, the pressure of the injected fluids and thepressure in formation are controlled to control the heating in theformation. The pressure in the formation may be controlled bycontrolling the production rate of fluids from the formation (forexample, the production rate of oxidation gases and/or syngas productsfrom heater/gas production wells 804). Heating in the formation may becontrolled so that there is enough hydrocarbon volume in the formationto maintain the oxidation reactions in the formation. Heating may becontrolled so that the formation near the injection wells is at atemperature that will generate desired synthesis gas if a synthesis gasgenerating fluid such as water is included in the oxidation fluid.Heating in the formation may also be controlled so that enough heat isgenerated to conductively heat the formation to mobilize, visbreak,and/or pyrolyze hydrocarbons in adjacent sections of the formation.

The process of injecting oxidizing fluid and/or water in one section,producing oxidation gases and/or syngas products in an adjacent sectionto heat the adjacent section, and producing upgraded hydrocarbons(mobilized, visbroken, and/or pyrolyzed hydrocarbons) from a subsequentsection may be continued in further sections of the tar sands formation.For example, FIG. 190 depicts a schematic of an embodiment of a thirdstage of treating the tar sands formation with fluid injection andoxidation. The gas heater/producer wells in section 794B are convertedto injection wells 788 to inject air and/or water. The producer wells insection 794C are converted to production wells (for example, heater/gasproduction wells 804) to produce oxidation gases and/or syngas products.Production wells 206 are formed in section 794D to produce upgradedhydrocarbons.

In some embodiments, significant amounts of residue and/or coke remainin a subsurface formation after heating the formation with heaters andproducing formation fluids from the formation. In some embodiments,sections of the formation include heavy hydrocarbons such as bitumenthat are difficult to heat to mobilization temperatures adjacent tosections of the formation that are being treated using an in situ heattreatment process. Heating of heavy hydrocarbons may require high energyinput, a large number of heater wells and/or increase in capital costs(for example, materials for heater construction). It would beadvantageous to produce formation fluids from subsurface formations withlower energy costs, fewer heater wells and/or heater cost with improvedproduct quality and/or recovery efficiency.

In some embodiments, a method for treating a subsurface formationincludes producing a at least a third hydrocarbons from a first portionby an in situ heat treatment process. An average temperature of thefirst portion is less than 350° C. An oxidizing fluid may be injected inthe first portion to cause the average temperature in the first portionto increase sufficiently to oxidize hydrocarbon in the first portion andto raise the average temperature in the first portion to greater than350° C. In some embodiments, the temperature of the first portion israised to an average temperature ranging from 350° C. to 700° C. A heavyhydrocarbon fluid that includes one or more condensable hydrocarbons maybe injected in the first portion to from a diluent and/or drive fluid.In some embodiments, a catalyst system is added to the first portion.

FIGS. 191, 192, and 193 depict side view representations of embodimentsof treating a subsurface formation in stages with heaters, oxidizingfluid, catalyst, and/or drive fluid. Hydrocarbon layer 484 may bedivided into three or more treatment sections. In certain embodiments,hydrocarbon layer 484 includes five treatment sections: section 794A,section 794B, section 794C, section 794D and section 794E. Sections 794Aand section 794C are separated by section 794B. Sections 794C andsection 794E are separated by section 794D. Section 794A through section794E may be horizontally displaced from each other in the formation. Insome embodiments, one side of section 794A is adjacent to an edge of thetreatment area of the formation or an untreated section of the formationis left on one side of section 794A before the same or a differentpattern is formed on the opposite side of the untreated section.

In certain embodiments, section 794A is heated to pyrolysis temperatureswith heaters 438. Section 794A may be heated to mobilize and/or pyrolyzehydrocarbons in the section. In some embodiments, section 794A is heatedto an average temperature of 250° C., 300° C., or up to 350° C. Themobilized and/or pyrolyzed hydrocarbons may be produced through one ormore production wells 206. Once at least a third, a substantial portion,or all of the hydrocarbons have been produced from section 794A, thetemperature in section 794A may be maintained at an average temperaturethat allows the section to be used as a reactor and/or reaction zone totreat formation fluid and/or hydrocarbons from surface facilities. Useof one or more heated portions of the formation to treat suchhydrocarbons may reduce or eliminate the need for surface facilitiesthat treat such fluids (for example, coking units and/or delayed cokingunits).

In certain embodiments, heating and producing hydrocarbons from sections794A creates fluid injectivity in the sections. After fluid injectivityhas been created in section 794A, an oxidizing fluid may be injectedinto the section. For example, oxidizing fluid may be injected insection 794A after at least a third or a majority of the hydrocarbonshave been produced from the section. The fluid may be injected throughheater wellbores, production wells 206, and/or injection wells locatedin section 794A. In some embodiments, heaters 438 continue to provideheat while the fluid is being injected. In certain embodiments, heaters438 may be turned down or off before or during fluid injection.

During injection of oxidant, excess oxidant and/or oxidation productsmay be removed from section 794A through one or more production wells206 and/or heater/gas production wells. In some embodiments, after theformation is raised to a desired temperature, a second fluid may beintroduced into section 794A. The second fluid may be water and/orsteam. Addition of the second fluid may cool the formation. For example,when the second fluid is steam and/or water, the reactions of the secondfluid with coke and/or hydrocarbons are endothermic and producesynthesis gas. In some embodiments, oxidizing fluid is added with thesecond fluid so that some heating of section 794A occurs simultaneouswith the endothermic reactions. In some embodiments, section 794A istreated in alternating steps of adding oxidant and second fluid to heatthe formation for selected periods of time.

In certain embodiments, the pressure of the injected fluids and thepressure section 794A are controlled to control the heating in theformation. The pressure in section 794A may be controlled by controllingthe production rate of fluids from the section (for example, theproduction rate of hydrocarbons, oxidation gases and/or syngasproducts). Heating in section 794A may be controlled so that sectionreaches a desired temperature (e.g., temperatures of at least 350° C.,of at least about 400° C., or at least about 500° C., about 700° C., orhigher). Injection of the oxidizing fluid may allow portions of theformation below the section heated by heaters to be heated, thusallowing heating of formation fluids in deeper and/or inaccessibleportions of the formation. The control of heat and pressure in thesection may improve efficiency and quality of products produced from theformation.

During heating and/or after heating of section 794A, heavy hydrocarbonswith low economic value and/or waste hydrocarbon streams from surfacefacilities may be injected in the section. Low economic valuehydrocarbons and/or waste hydrocarbon streams may include, but are notlimited to, hydrocarbons produced during surface mining operations,residue, bitumen and/or bottom extracts from bitumen mining. In someembodiments, hydrocarbons produced from section 794A or other sectionsof the formation may be introduced into section 794A. In someembodiments, one or more of the heater wells in section 794A areconverted to injection wells.

Heating of hydrocarbons and/or coke in section 794A may generate drivefluids. Generated drive fluids in section 794A may include air, steam,carbon dioxide, carbon monoxide, hydrogen, methane, pyrolyzedhydrocarbons and/or in situ diluent. In some embodiments, hydrocarbonfluids are introduced into section 794A prior to injecting an oxidizingfluid and/or the second fluid. Oxidation and/or thermal cracking ofintroduced hydrocarbon fluids may create the drive fluid.

In some embodiments, drive fluid may be injected into the formation. Theaddition of oxidizing fluid, steam, and/or water in the drive fluid maybe used to control temperatures in section 794A. For example, theaddition of hydrocarbons to section 794A may cool the averagetemperature in section 794A to a temperature below temperatures thatallow for cracking of the introduced hydrocarbons. Oxidizing fluid maybe injected to increase and/or maintain the average temperature between250° C. and 700° C. or between 350° C. and 600° C. Maintaining thetemperature between 250° C. and 700° C. may allow for the production ofhigh quality hydrocarbons from the low value hydrocarbons and/or wastestreams. Controlling the input of hydrocarbons, oxidizing fluid, and/ordrive fluid into section 794A may allow for the production ofcondensable hydrocarbons with a minimal amount non-condensable gases. Insome embodiments, controlling the input of hydrocarbons, oxidizingfluid, and/or drive fluid into section 794A may allow for the productionof large amounts of non-condensable hydrocarbons and/or hydrogen withminimal amounts of condensable hydrocarbons.

In some embodiments, a catalyst system is introduced to section 794Awhen the section is at a desired temperature (for example, a temperatureof at least 350° C., at least 400° C., or at least 500° C.). In someembodiments, the section is heated after and/or during introduction ofthe catalyst system. The catalyst system may be provided to theformation by injecting the catalyst system into one or more injectionwells and/or production wells in section 794A. In some embodiments, thecatalyst system is positioned in wellbores proximate the section of theformation to be treated. In some embodiments, the catalyst is introducedto one or more sections during in situ heat treatment of the sections.The catalyst may be provided to section 794A as a slurry and/or asolution in sufficient quantity to allow the catalyst to be dispersed inthe section. For example, the catalyst system may be dissolved in waterand/or slurried in an emulsion of water and hydrocarbons. Attemperatures of at least 100° C., at least 200° C., or at least 250° C.,vaporization of water from the solution allows the catalyst to bedispersed in the rock matrix of section 794A.

The catalyst system may include one or more catalysts. The catalysts maybe supported or unsupported catalysts. Catalysts include, but are notlimited to, alkali metal carbonates, alkali metal hydroxides, alkalimetal hydrides, alkali metal amides, alkali metal sulfides, alkali metalacetates, alkali metal oxalates, alkali metal formates, alkali metalpyruvates, alkaline-earth metal carbonates, alkaline-earth metalhydroxides, alkaline-earth metal hydrides, alkaline-earth metal amides,alkaline-earth metal sulfides, alkaline-earth metal acetates,alkaline-earth metal oxalates, alkaline-earth metal formates,alkaline-earth metal pyruvates, or commercially available fluidcatalytic cracking catalysts, dolomite, silicon-alumina catalyst fines,zeolites, zeolite catalyst fines any catalyst that promotes formation ofaromatic hydrocarbons, or mixtures thereof.

In some embodiments, fractions from surface facilities include catalystfines. Surface facilities may include catalytic cracking units and/orhydrotreating units. These fractions may be injected in section 794A toprovide a source of catalyst for the section. Injection of the fractionsin section 794A may provide an advantageous method for disposal and/orupgrading of the fractions as compared to conventional disposal methodsfor fractions containing catalyst fines.

After injecting catalyst in section 794A, the average temperature insection 794A may be increased or maintained in a range from about 250°C. to about 700° C., from about 300° C. to about 650° C., or from about350° C. to about 600° C. by injection of reaction fluids (for example,oxidizing fluid, steam, water and/or combinations thereof). In someembodiments, heaters 438 are used to raise or maintain the temperaturein section 794A in the desired range. In some embodiments, heaters 438and the introduction of reaction fluids into section 794A are used toraise or maintain the temperature in the desired range. Hydrocarbonfluids may be introduced in section 794A once the desired temperature isobtained. In some embodiments, the catalyst system is slurried with aportion of the hydrocarbons, and the slurry is introduced to section794A. In some embodiments, a portion of the hydrocarbon fluids areintroduced to section 794A prior to introduction of the catalyst system.The introduced hydrocarbon fluids may be hydrocarbons in formation fluidfrom an adjacent portion of the formation, and/or low valuehydrocarbons. The hydrocarbons may contact the catalyst system toproduce desirable hydrocarbons (for example, visbroken hydrocarbons,cracked hydrocarbons, aromatic hydrocarbons, or mixtures thereof). Thedesired temperature in section 794A may be maintained by turning onheaters in the section and/or continuous injection of oxidizing fluid tocause exothermic reactions that heat the formation.

In some embodiments, hydrocarbons produced through thermal and/orcatalytic treatment in section 794A may be used as a diluent and/or asolvent in the section. The produced hydrocarbons may include aromatichydrocarbons. The aromatic enriched diluent may dilute or solubilize aportion of the heavy hydrocarbons in section 794A and/or other sectionsin the formation (for example, sections 794B and/or 794C) and form amixture. The mixture may be produced from the formation (for example,produced from sections 794A and/or 794C). In some embodiments, themixture is produced from section 794B. In some embodiments, the mixturedrains to a bottom portion of the section and solubilizes additionalhydrocarbons at the bottom of the section. Solubilized hydrocarbons maybe produced or mobilized from the formation. In some embodiments, fluidsproduced in section 794A (for example, diluent, desirable products,oxidized products, and/or solubilized hydrocarbons) may be pushedtowards section 794B as shown by the arrows in FIG. 191 by oxidizingfluid, drive fluid, and/or created drive fluid.

In some embodiments, the temperatures in section 794A and the generationof drive fluid in section 794A increases the pressure of section 794A sothe drive fluid pushes fluids through section 794B into section 794C.Hot fluids flowing from section 794A into section 794B may melt,solubilize, visbreak and/or crack fluids in section 794B sufficiently toallow the fluids to move to section 794C. In section 794C, the fluidsmay be upgraded and/or produced through production wells 206.

In some embodiments, a portion of the catalyst system from section 794Aenters section 794B and/or section 794C and contacts fluids in thesections. Contact of the catalyst with formation fluids in 794B and/orsection 794C may result in the production of hydrocarbons having a lowerAPI gravity than the mobilized fluids.

The fluid mixture formed from contact of hydrocarbons, formation fluidand/or mobilized fluids with the catalyst system may be produced fromthe formation. The liquid hydrocarbon portion of the fluid mixture mayhave an API gravity between 10° and 25°, between 12° and 23° or between15° and 20°. In some embodiments, the produced mixture has at most 0.25grams of aromatics per gram of total hydrocarbons. In some embodiments,the produced mixture includes some of the catalysts and/or usedcatalysts.

In some embodiments, contact of the hydrocarbon fluids with the catalystsystem produces coke in 794A. Oxidizing fluid may be introduced intosection 794A. The oxidizing fluid may react with the coke to generateheat that maintains the average temperature of section 794A in a desiredrange. For some time intervals, additional oxidizing fluid may be addedto section 794A to increase the oxidation reactions to regeneratecatalyst in the section. The reaction of the oxidizing fluid with thecoke may reduce the amount of coke and heat formation and/or catalyst totemperatures sufficient to remove impurities on the catalyst. Coke,nitrogen containing compounds, sulfur containing compounds, and/ormetals such as nickel and/or vanadium may be removed from the catalyst.Removing impurities from the catalyst in situ may enhance catalyst life.After catalyst regeneration, introduction of reaction fluids may beadjusted to allow section 794A to return to an average temperature inthe desired temperature range. The average temperature in section 794Amay the controlled to be in range from about 250° C. to about 700° C.Hydrocarbons may be introduced in section 794A to continue the cycle.Additional catalyst systems may be introduced into the formation asneeded.

A method for treating a subsurface formation in stages may include usingan in situ heat treatment process in combination with injection of anoxidizing fluid and/or drive fluid in one or more portions (sections) ofthe formation. In some embodiments, hydrocarbons are produced from afirst portion and/or a third portion by an in situ heat treatmentprocess. A second portion that separates the first and third portionsmay be heated with one or more heaters to an average temperature of atleast about 100° C. The heat provided to the first portion may bereduced or turned off after a selected time. Oxidizing fluid may beinjected in the first portion to oxidize hydrocarbons in the firstportion and raise the temperature of the first portion. A drive fluidand/or additional oxidizing fluid may be injected and/or created in thethird portion to cause at least some hydrocarbons to move from the thirdportion through the second portion to the first portion of thehydrocarbon layer. Injection of the oxidizing fluid in the first portionmay be reduced or discontinued and additional hydrocarbons and/or syngasmay be produced from the first portion of the formation. The additionalhydrocarbons and/or syngas may include at least some hydrocarbons fromthe second and third portions of the formation. Transportation fuel maybe produced from the hydrocarbons produced from the first, second and/orthird portions of the formation. In some embodiments, a catalyst systemis provided to the first portion and/or third portion.

In certain embodiments, sections 794A and 794C are heated at or near thesame time to similar temperatures (for example, pyrolysis temperatures)with heaters 438. Sections 794A and 794C may be heated to mobilizeand/or pyrolyze hydrocarbons in the sections. The mobilized and/orpyrolyzed hydrocarbons may be produced (for example, through one or moreproduction wells 206) from section 794A and/or section 794C. Section794B may be heated to lower temperatures (for example, mobilizationtemperatures) by heaters 438. Sections 794D and 794E may not be heated.Little or no production of hydrocarbons to the surface may take placethrough section 794B, section 794D and/or section 794E. For example,sections 794A and 794C may be heated to average temperatures of at leastabout 300° C. or at least about 330° C. while section 794B is heated toan average temperature of at least about 100° C., sections 794D and 794Eare not heated and no production wells are operated in section 794B,section 794D, and/or section 794E. In some embodiments, heat fromsection 794A and/or section 794C transfers to sections section 794Dand/or section 794E.

In some embodiments, heavy hydrocarbons in section 794B may be heated tomobilization temperatures and flow into sections 794A and 794C. Themobilized hydrocarbons may be produce from production wells 206 insections 794A and 794C. After some or most of the fluids have beenproduced from sections 794A and 794C, production of formation fluids inthe sections may be slowed and/or discontinued.

In certain embodiments, heating and producing hydrocarbons from sections794A and 794C creates fluid injectivity in the sections. After fluidinjectivity has been created in section 794C, an oxidizing fluid may beinjected into the section. For example, oxidizing fluid may be injectedin section 794C after a majority of the hydrocarbons have been producedfrom the section. The fluid may be injected through heaters 438,production wells 206, and/or injection wells located in section 794C. Insome embodiments, heaters 438 continue to provide heat while the fluidis being injected. In certain embodiments, heaters 438 may be turneddown or off before or during fluid injection.

During injection of oxidant, excess oxidant and/or oxidation productsmay be removed from section 794C through one or more production wells206 and/or heater/gas production wells. In some embodiments, after theformation is raised to a desired temperature, a second fluid may beintroduced into section 794C. The second fluid may be steam and/orwater. Addition of the second fluid may cool the formation. For example,when the second fluid is steam and/or water, the reactions of the secondfluid with coke and/or hydrocarbons are endothermic and producesynthesis gas. In some embodiments, oxidizing fluid is added with thesecond fluid so that some heating of section 794C occurs simultaneouswith the endothermic reactions. In some embodiments, section 794C istreated in alternating steps of adding oxidant and second fluid to heatthe formation for selected periods of time.

In certain embodiments, the pressure of the injected fluids and thepressure section 794C are controlled to control the heating in theformation. The pressure in section 794C may be controlled by controllingthe production rate of fluids from the section (for example, theproduction rate of hydrocarbons, oxidation gases and/or syngasproducts). Heating in section 794C may be controlled so that there isenough hydrocarbon volume in the section to maintain the oxidationreactions in the formation. Heating and/or pressure in section 794C mayalso be controlled (for example, by producing a minimal amount ofhydrocarbons, oxidation gases and/or syngas products) so that enoughpressure is generated to create fractures in sections adjacent to thesection (for example, creation of fractures in section 794B). Creationof fractures in adjacent sections may allow fluids from adjacentsections to flow into section 794C and cool the section. Injection ofoxidizing fluid may allow portions of the formation below the sectionheated by heaters to be heated, thus allowing heating of formationfluids in deeper and/or inaccessible portions of the subsurface to beaccessed. Section 794C may be cooled from temperatures that promotesyngas production to temperatures that promote formation of visbrokenand/or upgrade products. Such control of heat and pressure in thesection may improve efficiency and quality of products produced from theformation.

During heating of section 794C or after the section has reached adesired temperature (e.g., temperatures of at least 300° C., at leastabout 400° C., or at least about 500° C.), an oxidizing fluid and/or adrive fluid may be injected and/or created in section 794A. The drivefluid includes, but is not limited to, steam, water, hydrocarbons,surfactants, polymers, carbon dioxide, air, or mixtures thereof. In someembodiments, the catalyst system described herein is injected in section794A. In some embodiments, the catalyst system is injected prior toinjecting the oxidizing fluid. In some embodiments, production of fluidfrom section 794A is discontinued prior to injecting fluids in thesection. In some embodiments, heater wells in section 794A are convertedto injection wells.

In some embodiments, drive fluids are created in section 794A. Createddrive fluids may include air, steam, carbon dioxide, carbon monoxide,hydrogen, methane, pyrolyzed hydrocarbons and/or diluent. In someembodiments, hydrocarbons (for example, hydrocarbons produced fromsection 794A and/or section 794C, low value hydrocarbons and/or or wastehydrocarbon streams) are provided as a portion of the drive fluid. Insome embodiments, hydrocarbons are introduced into section 794A prior toinjecting an oxidizing fluid and/or the second fluid. Oxidation,catalytic cracking, and/or thermal cracking of introduced hydrocarbonfluids may create the drive fluid and/or a diluent.

In some embodiments, oxidizing fluid, steam or water are provided as aportion of the drive fluid. The addition of oxidizing fluid, steam,and/or water in the drive fluid may be used to control temperatures inthe sections. For example, the addition of steam or water may be coolthe section. In some embodiments, water injected as the drive fluid isturned into steam in the formation due to the higher temperatures in theformation. The conversion of water to steam may be used to reducetemperatures or maintain temperatures in the sections between 270° C.and 450° C. Maintaining the temperature between 270° C. and 450° C. mayproduce higher quality hydrocarbons and/or generate a minimal amount ofnon-condensable gases.

Residual hydrocarbons and/or coke in section 794A may be melted,visbroken, upgraded and/or oxidized to produce products that may bepushed towards section 794B as shown by the arrows in FIG. 191. In someembodiments, the temperature in section 794C and the generation of drivefluid in section 794A may increase the pressure of section 794A so thedrive fluid pushes fluids through section 794B into section 794C. Hotfluids flowing from section 794A into section 794B may melt and/orvisbreak fluids in section 794B sufficiently to allow the fluids to moveto section 794C. In section 794C, the fluids may be upgraded and/orproduced through production wells 206.

In some embodiments, oxidizing fluid injected in section 794A iscontrolled to raise the average temperature in the section to a desiredtemperature (for example, at least about 350° C., or at least about 450°C.). Injection of oxidizing fluid and/or drive fluid in section 794A maycontinue until most or a substantial portion of the fluids from section794A are moved through section 794B to section 794C. After a period oftime, injection of oxidant and/or drive fluid into 794A is slowed and/ordiscontinued.

Injection of oxidizing fluid into section 794C may be slowed or stoppedduring injection and/or creation of drive fluid and/or creation ofdiluent in section 794A. In some embodiments, injection of oxidizingfluid in section 794C is continued to maintain an average temperature inthe section of about 500° C. during injection and/or creation of drivefluid and/or diluent in section 794A. In some embodiments, the catalystsystem is injected in section 794C.

As section 794A and/or section 794C are treated with oxidizing fluid,heaters in sections 794D and 794E may be turned on. In some embodiments,section 794D is heated through conductive heat transfer from section794C and/or convective heat transfer. Section 794E may be heated withheaters. For example, an average temperature in section 794E may beraised to above 300° C. while an average temperature in section 794D ismaintained between 80° C. and 120° C. (for example, at about 100° C.).

As temperatures in section 794E reach a desired temperature (forexample, above 300° C.), production of formation fluids from section794E through production wells 206 may be started. The temperature may bereached before, during or after oxidizing fluid and/or drive fluid isinjected and/or drive fluid and/or diluent is created in section 794A.

Once the desired temperature in section 794E has been obtained (forexample, above 300° C., or above 400° C.), production may be slowedand/or stopped in section 794C and oxidation fluid and/or drive fluid isinjected and/or created in section 794C to move fluids from section 794Cthrough cooler section 794D towards section 794E as shown by the arrowsin FIG. 192. Injection and/or creation of additional oxidation fluidand/or drive fluid in section 794C may upgrade hydrocarbons from section794B that are in section 794C and/or may move fluids towards section794E.

In some embodiments, heaters in combination with heating produced byoxidizing hydrocarbons in sections 794A, 794C and/or section 794E allowsfor a reduction in the number of heaters to be used in the sectionsand/or less capital costs as heaters made of less expensive materialsmay be used. The heating pattern may be repeated through the formation.

In some embodiments, fluids in hydrocarbon layer 484 (for example,layers in a tar sands formation) may preferentially move horizontallywithin the hydrocarbon layer from the point of injection because thelayers tend to have a larger horizontal permeability than verticalpermeability. The higher horizontal permeability allows the injectedfluid to move hydrocarbons between sections preferentially versus fluidsdraining vertically due to gravity in the formation. Providingsufficient fluid pressure with the injected fluid may ensure that fluidsare moved from section 794A through section 794B into section 794C forupgrading and/or production or from section 794C through section 794Dinto section 794E for upgrading and/or production. Increased heating insections 794A, 794C, and 794E may mobilize fluids from sections 794B and794D into adjacent sections. Increased heating may also mobilize fluidsbelow section 794A through 794E and the fluid may flow from the coldersections into the heated sections for upgrading and/or production due topressure gradients established by producing fluid from the formation. Insome embodiments, one or more production wells are placed in theformation below sections 794A through 794E to facilitate production ofadditional hydrocarbons.

In some embodiments, after sections 794A and 794C are heated to desiredtemperatures, the oxidizing fluid is injected into section 794C toincrease the temperature in the section. The fluids in section 794C maymove through section 794B into section 794A as indicated by the arrowsin FIG. 193. The fluids may be produced from section 794A. Once amajority of the fluids have been produced from section 794A, thetreatment process described in FIG. 191 and FIG. 192 may be repeated.

In some embodiments, treating a formation in stages includes heating afirst portion from one or more heaters located in the first portion.Hydrocarbons may be produced from the first portion. Heat provided tothe first portion may be reduced or turned off after a selected time. Asecond portion may be substantially adjacent to the first portion. Anoxidizing fluid may be injected in the first portion to cause atemperature of the first portion to increase sufficiently to oxidizehydrocarbons in the first portion and a third portion, the third portionbeing substantially below the first portion. The second portion may beheated from heat provided from the first portion and/or third portionand/or one or more heaters located in the second portion such that anaverage temperature in the second portion is at least about 100° C.Hydrocarbons may flow from the second portion into the first portionand/or third portion. Injection of the oxidizing fluid may be reduced ordiscontinued in the first portion. The temperature of the first portionmay cool to below 600° C. to 700° C. and additional hydrocarbons may beproduced from the first portion of the formation. The additionalhydrocarbons may include oxidized hydrocarbons from the first portion,at least some hydrocarbons from the second portion, at least somehydrocarbons from the third portion of the formation, or mixturesthereof. Transportation fuel may be produced from the hydrocarbonsproduced from the first, second and/or third portions of the formation.

In some embodiments, in situ heat treatment followed by oxidation and/orcatalyst addition as described for horizontal sections is performed invertical sections of the formation. Heating a bottom vertical layerfollowed by oxidation may create microfractures in middle sections thusallowing heavy hydrocarbons to flow from the “cold” middle section tothe warmer bottom section. Lighter fluids may flow into the top sectionand continue to be upgraded and/or produced through production wells. Insome embodiments, two vertical sections are treated with heatersfollowed by oxidizing fluid.

In some embodiments, heaters in combination with an oxidizing fluidand/or drive fluid are used in various patterns. For example,cylindrical patterns, square patterns, or hexagonal patterns may be usedto heat and produce fluids from a subsurface formation. FIG. 194 andFIG. 195, depict various patterns for treatment of a subsurfaceformation. FIG. 194 depicts an embodiment of treating a subsurfaceformation using a cylindrical pattern. FIG. 195 depicts an embodiment oftreating multiple sections of a subsurface formation in a rectangularpattern. FIG. 196 is a schematic top view of the pattern depicted inFIG. 195.

Hydrocarbon layer 484 may be separated into section 794A and section794B. Section 794A represents a section of the subsurface formation thatis to be produced using an in situ heat treatment process. Section 794Brepresents a section of formation that surrounds section 794A and is notheated during the in situ heat treatment process. In certainembodiments, section 794B has a larger volume than section 794A and/orsection 794C. Section 794A may be heated using heaters 438 to mobilizeand/or pyrolyze hydrocarbons in the section. The mobilized and/orpyrolyzed hydrocarbons may be produced (for example, through one or moreproduction wells 206) from section 794A. After some or all of thehydrocarbons in section 794A have been produced, an oxidizing fluid maybe injected into the section. The fluid may be injected through heaters438, a production well, and/or an injection well located in section794A. In some embodiments, at least a portion of heaters 438 are usedand/or converted to injection wells. In some embodiments, heaters 438continue to provide heat while the fluid is being injected. In otherembodiments, heaters 438 may be turned down or off before or duringfluid injection.

In some embodiments, providing oxidizing fluid such as air to section794A causes oxidation of hydrocarbons in the section and in portions ofsection 794C. In some embodiments, treatment of section 794A with theheaters creates coked hydrocarbons and formation with substantiallyuniform porosity and/or substantially uniform injectivity so thatheating of the section is controllable when oxidizing fluid isintroduced to the section. The oxidation of hydrocarbons in section 794Awill maintain the average temperature of the section or increase theaverage temperature of the section to higher temperatures (for example,above 400° C., above 500° C., above 600° C., or higher).

In some embodiments, an average temperature of section 794C that islocated below section 794A increases due to heat generated throughoxidation of hydrocarbons and/or coke in section 794A. For example, anaverage temperature in section 794C may increase from formationtemperature to above 500° C. As the average temperature in section 794Aand/or section 794C increases through oxidation reactions, thetemperature in section 794B increases and fluids may be mobilizedtowards section 794A as shown by the arrows in FIG. 194 and FIG. 195. Insome embodiments, section 794B is heated by heaters to an averagetemperature of at least about 100° C.

In section 794A, mobilized hydrocarbons are oxidized and/or pyrolyzed toproduce visbroken, oxidized, pyrolyzed products. For example, coldbitumen in section 794B may be heated to mobilization temperature of atleast about 100° C. so that it flows into section 794A and/or section794C. In section 794A and/or section 794C, the bitumen is pyrolyzed toproduce formation fluids. Fluids may be produced through productionwells 206 and/or heater/gas production wells in section 794A. In someembodiments, no fluids are produced from section 794A during oxidation.Injection of oxidizing fluid may be reduced or discontinued in section794A once a desired temperature is reached (for example, a temperatureof at least 350° C., at least 300° C., or above 450° C.). Once oxidizingfluid is slowed and/or discontinued in sections 794A, 794C, the sectionsmay cool (e.g. to temperatures below about 700° C., about 600° C., below500° C. or below 400° C.) and remain at upgrading and/or pyrolysistemperatures for a period of time. Fluids may continue to be upgradedand may be produced from section 794A through production wells.

In certain embodiments, section 794B and/or section 794D as described inreference to FIGS. 188-196 has a larger volume than section 794A,section 794C, and/or section 794E. Section 794B and/or section 794D maybe larger in volume than the other sections so that more hydrocarbonsare produced for less energy input into the formation. Because less heatis provided to section 794B and/or section 794D (the section is heatedto lower temperatures), having a larger volume in section 794B and/orsection 794D reduces the total energy input to the formation per unitvolume. The desired volume of section 794B and/or section 794D maydepend on factors such as, but not limited to, viscosity, oilsaturation, and permeability. In addition, the degree of coking is muchless in section 794B and/or section 794D due to the lower temperature soless hydrocarbons are coked in the formation when section 794B and/orsection 794D has a larger volume. In some embodiments, the lower degreeof heating in section 794B and/or section 794D allows for cheapercapital costs as lower temperature materials (cheaper materials) may beused for heaters used in section 794B and/or section 794D.

Using the remaining hydrocarbons for heat generation and only usingelectrical heating for the initial heating stage may improve the overallenergy use efficiency of treating the formation. Using electricalheating only in the initial step may decrease the electrical power needsfor treating the formation. In addition, forming wells that are used forthe combination of production, injection, and heating/gas production maydecrease well construction costs. In some embodiments, hot gasesproduced from the formation are provided to turbines. Providing the hotgases to turbines may recover some energy and improve the overall energyuse efficiency of the process used to treat the formation.

Treating the subsurface formation, as shown by the embodiments of FIGS.188-194 may utilize carbon remaining after production of mobilized,visbroken, and/or pyrolyzed hydrocarbons for heat generation in theformation. In some embodiment, treating hydrocarbons in the subsurfaceformation, as shown in by the embodiments in FIGS. 188-194 createsproducts having economic value from hydrocarbons having low economicvalue and/or from waste hydrocarbon streams from surface facilities.

A downhole heater assembly may include 5, 10, 20, 40, or more heaterscoupled together. For example, a heater assembly may include between 10and 40 heaters. Heaters in a downhole heater assembly may be coupled inseries. In some embodiments, heaters in a heater assembly may be spacedfrom about 8 meters (about 25 feet) to about 60 meters (about 195 feet)apart. For example, heaters in a heater assembly may be spaced about 15meters (about 50 feet) apart. Spacing between heaters in a heaterassembly may be a function of heat transfer from the heaters to theformation. Spacing between heaters may be chosen to limit temperaturevariation along a length of a heater assembly to acceptable limits.Heaters in a heater assembly may include, but are not limited to,electrical heaters, flameless distributed combustors, naturaldistributed combustors, and/or oxidizers. In some embodiments, heatersin a downhole heater assembly may include only oxidizers.

FIG. 197 depicts a schematic of an embodiment of downhole oxidizerassembly 612 including oxidizers 614 connected in series. In someembodiments, oxidizer assembly 612 may include oxidizers 614 andflameless distributed combustors. Oxidizer assembly 612 may be loweredinto an opening in a formation and positioned as desired. In someembodiments, a portion of the opening in the formation may besubstantially parallel to the surface of the Earth. In some embodiments,the opening of the formation may be otherwise angled with respect to thesurface of the Earth. In an embodiment, the opening may include asignificant vertical portion and a portion otherwise angled with respectto the surface of the Earth. In certain embodiments, the opening may bea branched opening. Oxidizer assemblies may branch from common fueland/or oxidant conduits in a central portion of the opening.

Oxidizing fluid 806 may be supplied to oxidizer assembly 612 throughoxidant conduit 618. In some embodiments, fuel conduit 616 and/oroxidizers 614 may be positioned concentrically, or substantiallyconcentrically, in oxidant conduit 618. In some embodiments, fuelconduit 616 and/or oxidizers 614 may be arranged other thanconcentrically with respect to oxidant conduit 618. In certain branchedopening embodiments, fuel conduit 616 and/or oxidant conduit 618 mayhave a weld or coupling to allow placement of oxidizer assemblies 612 inbranches of the opening. Exhaust gas 808 may pass through outer conduit620 and out of the formation.

In some embodiments, the downhole oxidizer assembly includes a waterconduit positioned in the oxidant conduit to deliver water to the fuelconduit prior to the first oxidizer in the oxidizer assembly. A portionof the water conduit may pass through a heated zone generated by thefirst oxidizer prior to a water entry point into the fuel conduit. Insome embodiments, the fuel conduit is positioned adjacent to theoxidizers, and branches from the fuel conduit provide fuel to the otheroxidizers. In some embodiments, the fuel conduit may comprise one ormore orifices to selectively control the pressure loss along the fuelconduit.

Fuel 810 may be supplied to oxidizers 614 through fuel conduit 616. Insome embodiments, the fuel for the oxidizers includes synthesis gas. Insome embodiments, the fuel includes synthesis gas (for example, amixture that includes hydrogen and carbon monoxide) that was producedusing an in situ heat treatment process. In certain embodiments, thefuel may comprise natural gas mixed with heavier components such asethane, propane, butane, or carbon monoxide. In some embodiments, thefuel and/or synthesis gas may include non-combustible gases such asnitrogen. In some embodiments, the fuel contains products from a coal orheavy oil gasification process. The coal or heavy oil gasificationprocess may be an in situ process or an ex situ process. Afterinitiation of combustion of fuel and oxidant mixture in oxidizers 614,composition of the fuel may be varied to enhance operational stabilityof the oxidizers.

In certain embodiments, fuel used to initiate combustion may be enrichedto decrease the temperature required for ignition or otherwisefacilitate startup of oxidizers 614. In some embodiments, hydrogen orother hydrogen rich fluids may be used to enrich fuel initially suppliedto the oxidizers. After ignition of the oxidizers, enrichment of thefuel may be stopped. In some embodiments, a portion or portions of fuelconduit 616 may include a catalytic surface (for example, a catalyticouter surface) to decrease an ignition temperature of fuel 810.

In some embodiments, non-condensable gases produced from treatment areasof in situ heat treatment processes are used as fuel for heaters thatheat treatment areas in the formation. The heaters may be burners. Theburners may be oxidizers of downhole oxidizer assemblies, flamelessdistributed combustors and/or burners that heat a heat transfer fluidused to heat the treatment areas. The non-condensable gases may includecombustible gases (for example, hydrogen, hydrogen sulfide, methane andother hydrocarbon gases) and noncombustible gases (for example, carbondioxide). The presence of noncombustible gases may inhibit coking of thefuel and/or may reduce the flame zone temperature of oxidizers when thefuel is used as fuel for oxidizers of downhole oxidizer assemblies. Thereduced flame zone temperature may inhibit formation of NOx compoundsand/or other undesired combustion products by the oxidizers. Othercomponents such as water may be included in the fuel supplied to theburners. Combustion of in situ heat treatment process gas may reduceand/or eliminate the need for gas treatment facilities and/or the needto treat the non-condensable portion of formation fluid produced usingthe in situ heat treatment process to obtain pipeline gas and/or othergas products. Combustion of in situ heat treatment process gas inburners may create concentrated carbon dioxide and/or SO_(x) effluentsthat may be used in other processes, sequestered and/or treated toremove undesired components.

In some embodiments, use of non-condensable fluids from in situ heattreatment processes in burners reduces or eliminates the need to buildpower plants near the in situ heat treatment processes. Heat initiallyused to increase the temperature of treatment areas in the formation maybe provided by burning pipeline gas or other fuel. After the formationbegins producing formation fluid, a portion or all of thenon-condensable fluids produced from the formation may replace orsupplement the pipeline gas or other fuel used to heat treatment areas.

In some embodiments, the oxidizing fluid supplied to the burners is airor enriched air. In some embodiments, the oxidizing fluid is produced byblending oxygen with a carrier fluid such as carbon dioxide to reduce oreliminate the presence of nitrogen in the oxidizing fluid. For example,the oxidizing fluid may be about 50% by volume oxygen and about 50% byvolume carbon dioxide. Eliminating or reducing nitrogen in the oxidizingfluid may eliminate or reduce the amount of NOx compounds generated bythe burners. Eliminating or reducing nitrogen in the oxidizing fluid mayalso enable transporting and geologically storing exhaust gases from theburners without having to separate nitrogen from the exhaust gases.

FIG. 198 depicts an embodiment of a system that uses non-condensablefluid from an in situ heat treatment process to heat a treatment area ina formation. Formation fluid 212 produced from treatment areas in theformation enters separation unit 214. Separation unit 214 may separatethe formation fluid into in situ heat treatment process liquid stream216, in situ heat treatment process gas 218, and aqueous stream 220. Insitu heat treatment process gas 218 may entrain some water and/orcondensable hydrocarbons. In situ heat treatment process gas 218 entersgas separation unit 222. Gas separation unit 222 may remove one or morecomponents from in situ heat treatment process gas 218 to produce fuel812 and one or more other streams 814. For example, other streams 814may include carbon dioxide streams 266 and 314 from processes describedin FIGS. 2-6. Fuel 812 may include, but is not limited to, hydrogen,sulfur compounds, hydrocarbons having a carbon number of at most 5,carbon oxides, nitrogen compounds, or mixtures thereof. Fuel 812 mayinclude streams produced as described in FIGS. 2-6 (for example, streams244, 250, 258, 264, 288, 290, or mixtures thereof). In some embodiments,gas separation unit 222 uses chemical and/or physical treatment systemsand/or systems described in FIGS. 2-6 to remove or reduce the amount ofcarbon dioxide in fuel 812. In some embodiments, in situ heat treatmentprocess gas 218 is minimally treated before being used as a fuel. Forexample, gas separation unit 222 may minimally treat in situ heattreatment process gas 218 to remove water and/or hydrocarbons having acarbon number greater than 5. In some embodiments, in situ heattreatment process gas 218 is suitable for use as a fuel so the gasseparation unit 222 is not necessary.

Fuel 812 may enter fuel conduit 616 that provides fuel to oxidizers ofoxidizer assemblies (for example, a plurality of oxidizer assembliessuch as downhole oxidizer assembly as described in U.S. PublishedApplication No. 20080135254 to Vinegar et al.) that heat treatment area816. Air stream 818 and/or diluent fluid 820 may be mixed with oxidizingfluid 806 to form mixed oxidizing fluid 822 that is provided to theoxidizers of the downhole oxidizing assemblies. Diluent fluid 820 maybe, but is not limited to, carbon oxides separated from in situ heattreatment process gas 218, a portion of stream 814 from gas separationunit 222, carbon dioxide 824 from the exhaust of the downhole oxidizingassemblies, separated carbon dioxide gas streams from gas separationsystems described in FIGS. 2-6, or mixtures thereof. In someembodiments, diluent fluid 820 includes sufficient amounts of carbondioxide to inhibit oxidation of conduits and/or metal parts in fuelconduit 616 that come in contact with oxidizing fluid 806. In someembodiments, the amount of excess oxidant supplied to the downholeoxidizers is reduced to less than about 50% excess oxidant by volume bymixing oxidizing fluid 806 with the diluent fluid 820.

Initially, pipeline gas or other fuel may be supplied to treatment area816. Valves 826 may be adjusted to control the amount of initial fuelsupplied to treatment area 816 as fuel 812 becomes available. Initially,air stream 818 may be supplied to treatment area 816 as the oxidizingfluid. After additional oxidant sources become available, valves 826′may be adjusted to control the composition of oxidizing fluid 822provided to treatment area 816.

Exhaust gas 808 from burners used to heat treatment area 816 may bedirected to exhaust treatment unit 828. Exhaust gas 808 may include, butis not limited to, carbon dioxide and/or SO_(x). In exhaust separationunit 828, carbon dioxide stream 824 is separated from SO_(x) stream 830.Separated carbon dioxide stream 824 may be mixed with diluent fluid 820,may be used as a carrier fluid for oxidizing fluid 806, may be used as adrive fluid for producing hydrocarbons, and/or may be sequestered.SO_(x) stream 830 may be treated using known SO_(x) treatment methods(for example, sent to a Claus plant). Formation fluid 212′ produced fromheat treatment area 816 may be mixed with formation fluid 212 from othertreatment areas and/or may enter separation unit 214.

In some embodiments, onsite production of oxygen gas is desirable.Production of oxygen gas at or proximate downhole oxidizer assembliesmay reduce production costs and/or enhance efficiency of operation ofthe production of formation fluids. Oxygen gas may be produced byseparation of oxygen from air using cryogenic and/or non-cryogenicsystems. Non-cryogenic systems include, but are not limited to, pressureswing adsorption, vacuum swing adsorption, vacuum-pressure swingadsorption, membranes, or combinations thereof. Cryogenic systems relyon differences in boiling points to separate and purify the desiredproducts.

FIG. 199 depicts a schematic representation of an embodiment of a systemfor producing oxygen for use as a portion of oxidizing fluid 822provided to burners used to heat treatment area 816. Air stream 818enters air separation unit 832. In air separation unit 832, air 818 isseparated into oxygen steam 834 and nitrogen stream 836.

Oxygen stream 834 enters mixed oxidizing fluid 822 and/or is mixed withoxidizing fluid 806. A portion of nitrogen stream 836 may be recycled toair separation unit 832 for use as a coolant. Nitrogen stream 836 may beused as a drive fluid, as a reactant to produce ammonia, as a coolantfor forming a low temperature barrier, as a fluid used during drilling,or as a fluid for other processes.

In some embodiments, oxygen is produced through the decomposition ofwater. For example, electrolysis of water produces oxygen and hydrogen.Using water as a source of oxygen provides a source of oxidant withminimal or no carbon dioxide emissions. The produced hydrogen may beused as a hydrogenation fluid for treating hydrocarbon fluids in situ orex situ, a fuel source and/or for other purposes. FIG. 200 depicts aschematic representation of an embodiment of a system for producingoxygen using electrolysis of water for use in an oxidizing fluidprovided to burners that heat treatment area 816. Water stream 838enters electrolysis unit 840. In electrolysis unit 840, current isapplied to water stream 838 and produces oxygen stream 842 and hydrogenstream 844. In some embodiments, electrolysis of water stream 838 isperformed at temperatures ranging from about 600° C. to about 1000° C.,from about 700° C. to about 950° C., or from 800° C. to about 900° C. Insome embodiments, electrolysis unit 840 is powered by nuclear energyand/or a solid oxide fuel cell and/or a molten salt fuel cell. The useof nuclear energy and/or a solid oxide fuel cell and/or a molten saltfuel cell provides a heat source with minimal and/or no carbon dioxideemissions. High temperature electrolysis may generate hydrogen andoxygen more efficiently than conventional electrolysis because energylosses resulting from the conversion of heat to electricity andelectricity to heat are avoided by directly utilizing the heat producedfrom the nuclear reactions without producing electricity. Oxygen stream842 mixes with mixed oxidizing fluid 822 and/or is mixed with oxidizingfluid 806. A portion or all of hydrogen stream 844 may be recycled toelectrolysis unit 840 and used as an energy source. A portion or all ofhydrogen stream 844 may be used for other purposes such as, but notlimited to, a fuel for burners and/or a hydrogen source for in situ orex situ hydrogenation of hydrocarbons.

Exhaust gas 808 from burners used to heat treatment area 816 may bedirected to exhaust treatment unit 828. Exhaust gas 808 may include, butis not limited to, carbon dioxide and/or SO_(x). In exhaust separationunit 828, carbon dioxide stream 824 is separated from SO_(x) stream 830.Separated carbon dioxide stream 824 may be mixed with diluent fluid 820,may be used as a carrier fluid for oxidizing fluid 806, may be used as adrive fluid for producing hydrocarbons, and/or may be sequestered.SO_(x) stream 830 may be treated using known SO_(x) treatment methods(for example, sent to a Claus plant). Formation fluid 212′ produced fromheat treatment area 816 may be mixed with formation fluid 212 from othertreatment areas and/or formation fluid 212′ may enter separation unit214. Separation unit 214 may separate the formation fluid into in situheat treatment process liquid stream 216, in situ heat treatment processgas 218, and aqueous stream 220. Gas separation unit 222 may remove oneor more components from in situ heat treatment process gas 218 toproduce fuel 812 and one or more other streams 814. Fuel 812 mayinclude, but is not limited to, hydrogen, sulfur compounds, hydrocarbonshaving a carbon number of at most 5, carbon oxides, nitrogen compounds,or mixtures thereof. In some embodiments, gas separation unit 222 useschemical and/or physical treatment systems to remove or reduce theamount of carbon dioxide in fuel 812. Fuel 812 may enter fuel conduit616 that provides fuel to oxidizers of oxidizer assemblies that heattreatment area 816.

In some embodiments, electrolysis unit 840 is powered by nuclear energy.Nuclear energy may be provided by a number of different types ofavailable nuclear reactors and nuclear reactors currently underdevelopment (for example, generation IV reactors). In some embodiments,nuclear reactors may include a self-regulating nuclear reactor.Self-regulating nuclear reactors may include a fissile metal hydridewhich functions as both fuel for the nuclear reaction as well as amoderator for the nuclear reaction. The nuclear reaction may bemoderated by the temperature driven mobility of the hydrogen isotopecontained in the hydride. Self-regulating nuclear reactors may producethermal power on the order of tens of megawatts per unit.Self-regulating nuclear reactors may operate at a maximum fueltemperature ranging from about 400° C. to about 900° C., from about 450°C. to about 800° C., and from about 500° C. to about 600° C.Self-regulating nuclear reactors have several advantages including, butnot limited to, a compact/modular design, ease of transport, and asimple cost effective design.

In some embodiments, nuclear reactors may include one or more very hightemperature reactors (VHTRs). VHTRs may use helium as a coolant to drivea gas turbine for treating hydrocarbon fluids in situ, poweringelectrolysis unit 840 and/or for other purposes. VHTRs may produce heatfor electrolysis units up to about 950° C. or more. In some embodiments,nuclear reactors may include a sodium-cooled fast reactor (SFR). SFRsmay be designed on a smaller scale (for example, 50 MWe), and thereforeare more cost effective to manufacture on site for treating hydrocarbonfluids in situ, powering electrolysis units and/or for other purposes.SFRs may be of a modular design and potentially portable. SFRs mayproduce heat for electrolysis units ranging from about 500° C. to about600° C., from about 525° C. to about 575° C., or from 540° C. to about560° C.

In some embodiments, pebble bed reactors may be employed to provide heatfor electrolysis. Pebble bed reactors may produce up to about 165 MWe.Pebble bed reactors may produce heat for electrolysis units ranging fromabout 500° C. to about 1100° C., from about 800° C. to about 1000° C.,or from about 900° C. to about 950° C. In some embodiments, nuclearreactors may include supercritical-water-cooled reactors (SCWRs) basedat least in part on previous light water reactors (LWR) andsupercritical fossil-fired boilers. In some embodiments, SCWRs may beemployed to provide heat for electrolysis. SCWRs may produce heat forelectrolysis units ranging from about 400° C. to about 650° C., fromabout 450° C. to about 550° C., or from about 500° C. to about 550° C.

In some embodiments, nuclear reactors may include lead-cooled fastreactors (LFRs). In some embodiments, LFRs may be employed to provideheat for electrolysis. LFRs may be manufactured in a range of sizes,from modular systems to several hundred megawatt or more sized systems.LFRs may produce heat for electrolysis units ranging from about 400° C.to about 900° C., from about 500° C. to about 850° C., or from about550° C. to about 800° C.

In some embodiments, nuclear reactors may include molten salt reactors(MSRs). In some embodiments, MSRs may be employed to provide heat forelectrolysis. MSRs may include fissile, fertile, and fission isotopesdissolved in a molten fluoride salt with a boiling point of about 1,400°C. which function as both the reactor fuel and the coolant. MSRs mayproduce heat for electrolysis units ranging from about 400° C. to about900° C., from about 500° C. to about 850° C., or from about 600° C. toabout 800° C.

FIG. 201 depicts a schematic representation of an embodiment of a systemfor producing hydrogen for use as a fuel for burners that heat treatmentarea 816. In situ heat treatment process gas 218 and/or fuel 812 maypass to reformation unit 846. In some embodiments, in situ heattreatment process gas 218 is mixed with fuel 812 and then passed toreformation unit 846. A portion of in situ heat treatment process gas218 enters gas separation unit 222. Gas separation unit 222 may removeone or more components from in situ heat treatment process gas 218 toproduce fuel 812 and one or more other streams 814. Other streams 814may include carbon dioxide and/or hydrogen sulfide. The carbon dioxidemay be mixed with diluent fluid 820, may be used as a carrier fluid foroxidizing fluid 806, may be used as a drive fluid for producinghydrocarbons, may be vented, and/or may be sequestered. Hydrogen sulfidemay be sent to a Claus plant for conversion to sulfur compounds orsulfur, may be burned to produce heat, and/or may be sequestered in aformation. Fuel 812 may include, but is not limited to, hydrogen,hydrocarbons having a carbon number of at most 5, or mixtures thereof.Some or all of fuel 812 may pass to fuel conduit 616.

Reformer unit 846 may be, for example, an autothermal reformer and/or asteam reformer. Reformer unit 846 may include one or more catalysts thatenhance the production of hydrogen and carbon dioxide from hydrocarbons.For example, reformation unit 846 may include water gas shift catalysts.Reformation unit 846 may include one or more separation systems (forexample, membranes and/or a pressure swing adsorption system) capable ofseparating hydrogen from other components. Reformation of fuel 812and/or in situ heat treatment process gas 218 may produce hydrogenstream 844 and carbon oxide stream 848. Reformation of fuel 812 and/orin situ heat treatment process gas 218 may be performed using techniquesknown in the art for catalytic and/or thermal reformation ofhydrocarbons to produce hydrogen. In some embodiments, fuel 812 and/orin situ heat treatment process gas 218 is passed through a drying systemprior to entering reformation unit 846 to remove water in the fueland/or gas.

Hydrogen stream 844 may be provided to fuel conduit 616. A portion orall of hydrogen stream 844 may be used for other purposes such as, butnot limited to, an energy source and/or a hydrogen source for in situ orex situ hydrogenation of hydrocarbons. Valves 826 may be adjusted tocontrol the amount of initial fuel supplied to treatment area 816 asfuel 812 and/or hydrogen stream 844 become available.

Carbon oxide stream 848 may include, but is not limited to, carbondioxide and carbon monoxide. Carbon oxide stream 848 may be mixed withdiluent fluid 820, may be used as a carrier fluid for oxidizing fluid806, may be used as a drive fluid for producing hydrocarbons, may bevented, and/or may be sequestered.

Combinations of processes described in FIGS. 198 through 201 may be usedto produce fuel and/or oxidizing fluid for burners that provide heat toheat treatment area 816.

Coke formation may occur inside the fuel conduit if the fuel containshydrocarbons and the heat flux is sufficiently high. After oxidizerignition, steps may be taken to reduce coking. For example, steam orwater may be added to the fuel conduit. In some embodiments, coking isinhibited by decreasing a residence time of fuel in the fuel conduit.The residence time of fuel in the fuel conduit may be decreased byvarying the size of the fuel conduit. For example, one portion of thefuel conduit may be approximately ¾ inch (approximately 1.9 cm) indiameter while another portion may be approximately ⅜ inch(approximately 0.95 cm) in diameter. Alternatively, the thickness andlength of all or portions of the fuel conduit may be varied.

In some embodiments, coking is inhibited by insulating portions of thefuel conduit that pass through high temperature zones proximate theoxidizers. For example, a portion of the fuel conduit may be coated withan insulating layer and/or a conductive layer. The insulating layer maybe made from thermal insulating materials such as silicon carbide,alumina, mullite, zirconia, and other material known in the art. Theconductive layer may be made from commercially available highlyconductive materials such as ceramics and/or high temperature metals,including but not limited to Hexyloy (available from Arklay S. RichardsCo., Inc.). The insulating layer and/or the conductive layer may beapplied to the fuel conduit using a high velocity oxygen fuel or airplasma process. The resulting layer or layers may be heat treated.

In some embodiments, the fuel conduit is treated to remove coke formedin the fuel conduit by decoking. Decoking may be performed throughmechanical means and/or chemical means. For example, coke may be removedfrom the fuel conduit by pumping a metal studded, foam or plastic pigthrough the fuel conduit. In an embodiment, a rod is inserted into fuelconduit 616 to dislodge coke particles and push them towards the lastoxidizer in the oxidizer assembly. The rod may be a hydrolance or otherhigh pressure pipe or tube used to direct high pressure water, air,nitrogen, and/or other gas to dislodge the coke.

FIG. 202 and FIG. 203 depict embodiments of oxidizers 614 of oxidizerassemblies positioned in outer conduits 620. Oxidizer 614 may be coupledto fuel conduit 616 that is positioned in oxidant conduit 618. Oxidantand fuel enter mix chamber 850 of oxidizer 614. A combustible mixture offuel and oxidant passes from mix chamber 850 into the space between fuelconduit 616 and shield 852. Shield 852 surrounds a portion of fuelconduit 616. Shield 852 may allow development of flame zone 622 inoxidizer 614. Shield 852 may inhibit gas flowing in the oxidant conduitfrom extinguishing flame zone 622 formed in oxidizer 614. Spacers mayposition oxidizer 614 in oxidant conduit 618. The spacers may be coupledto shield 852 and/or to oxidizer conduit 618. An igniter and/orcombusting fuel in flame zone 622 oxidizes the mixture of fuel andoxidant in the flame zone.

Insulating layer 854 may be placed around fuel conduit 616 to at leastpartially surround a portion of the fuel conduit. Insulating layer 854may be made of a material with low thermal conductivity. Insulatinglayer 854 may inhibit coking in fuel conduit 616. Insulating layer 854may only surround portions of fuel conduit 616 that pass throughoxidizers 614. In some embodiments, the insulating layer covers theportion of the fuel conduit passing through the oxidizer and a portionof the fuel conduit before and/or after the oxidizer. In someembodiments, the entire fuel conduit is insulated.

Thermally conductive layer 856 may surround or partially surroundinsulating layer 854. Thermally conductive layer 856 may be locatedadjacent to flame zone 622. Thermally conductive layer 856 may spreadthe heat of flame zone 622 over a large area to help reduce thetemperature applied to insulating layer 854 below the flame zone. Insome embodiments, the insulating layer does not include a thermallyconductive layer.

FIG. 203 depicts a cross-sectional representation of an embodiment ofoxidizer 614 with gas cooled sleeve 858. A portion of sleeve 858 maypass through oxidizer 614 to form an annular space. One or more spacersmay be located between fuel conduit 616 and sleeve 858 to position thesleeve relative to the fuel conduit. One or more feedthroughs 860 maydirect fuel from fuel conduit 616 to mix chamber 850 and/or to the areabetween shield 852 and the fuel conduit of oxidizer 614. Some gasflowing in oxidant conduit 618 passes between fuel conduit 616 andinsulating sleeve 854. Insulating sleeve 854 may include thermallyconductive layer 856 to dissipate some of the heat from flame zone 622over a large area. Gas passing between fuel conduit 616 and insulatingsleeve 854 may inhibit excessive heating of the fuel conduit adjacent toflame zone 622.

The flow of fuel in fuel conduit 616 is represented by arrow 862, andthe flow of gas (for example, air and exhaust products and unburned fuelfrom previous oxidizers) in oxidant conduit 618 is represented by arrow864. Exhaust gases from all oxidizers in the oxidizer assembly passthrough outer conduit 620 in the direction indicated by arrow 866. Flowof gas between fuel conduit 616 and insulating sleeve 854 may reduce theamount of heat transfer from the insulating sleeve to the fuel conduit.Flame zone 622 may have a temperature of about 1100° C. (about 2000° F.)while the temperature in oxidant conduit adjacent to the shield ofoxidizer 614 may be about 700° C. (about 1300° F.).

Oxidant may be supplied through the oxidant conduit to the oxidizers.Oxidizing fluid may include, but is not limited to, air, oxygen enrichedair, and/or hydrogen peroxide. Depletion of oxygen in the oxidant mayoccur toward a terminal end of an oxidizer assembly. In someembodiments, the amount of excess oxidant supplied to the oxidizers isreduced to less than about 50% excess oxidant by weight by controllingthe pressure, temperature, and flow rate of the oxidant in the oxidantconduit. For example, after ignition, the amount of oxidant can bereduced when the temperature of the fuel conduit reaches about 650° C.(about 1200° F.). In some embodiments, the amount of excess oxidant isreduced to less than about 25% excess oxidant by weight. In otherembodiments, the amount of excess oxidant is reduced to less than about10% excess oxidant by weight.

In some embodiments, the amount of excess oxidant is reduced when thetemperature downstream of the oxidizers becomes sufficiently hot tosupport reaction of oxidant and fuel outside of the oxidizers. Oxidantand fuel may react in regions between oxidizers. During such operation,the oxidizer assembly functions much like a flameless distributedcombustor. Generating heat in the regions between the oxidizers mayresult in a smoother temperature profile along the length of theoxidizer assembly. The excess oxidant may be reduced such that the lastoxidizer in the oxidizer assembly substantially eliminates the remainingoxidant in the oxidant conduit. The last oxidizer may be a catalyticoxidizer to minimize or eliminate oxidant remaining in the oxidantconduit.

When the temperature along the length of the oxidizer assembly increasesto a temperature sufficient to support reaction of oxidant with fueloutside of the shields of the oxidizers, the mode of operation of theoxidizer assembly may shift from a series of individual oxidizers withaerodynamically staged flames to a more uniformly distributed or“reactor-stable” mode of operation. During the reactor-stable mode ofoperation, combustion may take place outside the shield along the entirelength of the oxidant conduit. Under this condition stability isachieved by balancing overall heat loss and heat generation over thebroad reaction zone. Local recirculation of hot combustion products toincoming reactants enables minimum reaction temperature wherefuel-oxidant mixtures will oxidize without aerodynamic stabilization. Inthis mode of operation, the oxidizers may still serve as a “safety” ormeans of continuing stabilization, if the temperature falls below thetemperature needed to sustain oxidation of the fuel and oxidant in oneor more regions of the oxidizer. During reactor-stable mode ofoperation, the amount of excess oxygen supplied to the oxidizer assemblymay be reduced. Having the ability to reduce the amount of excess oxygensupplied to the oxidizer assembly may significantly improve the overalleconomics of the system used to heat the formation.

A common problem associated with the operation of gas burners employinga flame mechanism is that at high temperatures, particularly above about1500° C. (about 2730° F.), oxygen and nitrogen present in the aircombine by a thermal formation mechanism to form pollutants such as NOand NO₂, commonly referred to as NO_(x). By controlling the flow of fueland oxidant, and by maintaining a distributed temperature, the formationof NO_(x) may be inhibited. In some embodiments, the flow of fuel andoxidant is controlled to produce less than about 10 parts per million byweight of NO_(x) from the gas burner. The flow of oxidant may becontrolled by having openings in shields of the oxidizers sized to bringa sufficient flow rate to the flame zone to dilute the flame withoutcausing the flame to be extinguished. Additionally, water added to thefuel conduit may inhibit NO_(x) formation.

In some embodiments, initiation of the burner assembly is accomplishedby initializing combustion in a specified sequence beginning with thelast oxidizer in the assembly. Referring to FIG. 197, oxidizer assembly612 includes first oxidizer 868, last oxidizer 870, and second-to-lastoxidizer 872. In some embodiments, fuel is supplied through fuel conduit616, and oxidant is supplied through oxidant conduit 618 to provide afirst combustible mixture to last oxidizer 870. Combustion is initiatedin last oxidizer 870 and the supply of oxidant is adjusted to supplysecond-to-last oxidizer 872 with a second combustible mixture. Ignitionof last oxidizer 870 is maintained as second-to-last oxidizer 872 isignited. Thereafter this process of adjusting the supply of oxidant toprovide a combustible fuel and oxidant mixture to the next unignitedoxidizer and initiating combustion in the unignited oxidizer is repeateduntil first oxidizer 868 is ignited. In some embodiments, the fuelpressure is greater than the oxidant pressure at an oxidizer beforeinitiating combustion in the oxidizer.

In an embodiment, the start up sequence is optimized by controlling theoxidant and fuel pressure differential along the length of the oxidizerassembly. Because the pressure differential varies over the length ofthe burner assembly, a planned sequential ignition from oxidizer tooxidizer, starting with last (most remote) oxidizer 870 may be achieved.In this embodiment, the fuel-oxidant mixture in the ignition region isoptimized at last oxidizer 870, then at the second to last oxidizer 872,and so on, with the fuel-to-oxidant ratio being least optimal at firstoxidizer 868. The profiles may be controlled to change the sequence ofignition. In an embodiment, the profiles may be reversed so that firstoxidizer 868 is ignited first. Altering the profiles may comprisealtering the pressure differential along the oxidizer assembly length bydesign of the fuel conduit diameter coupled with optimization of openingsizes that provide fuel to the oxidizers, of opening sizes that provideoxidant to the mix chambers of the oxidizers, and of openings in theshields that supply oxidant to the flame zone. In addition, control maybe facilitated by flow restrictions positioned in fuel conduit 616.

FIG. 204 depicts a perspective view of an embodiment of oxidizer 614 ofthe downhole oxidizer assembly. Oxidizer 614 may include mix chamber850, igniter holder 874, ignition chamber 876, and shield 852. Fuelconduit 616 may pass through oxidizer 614. Fuel conduit 616 may have oneor more fuel openings 878 within mix chamber 850 (as shown in FIG. 202).In some embodiments, additional openings in fuel conduit 616 allowadditional fuel to pass into the space between the fuel conduit andshield 852. Openings 880 allow oxidant to flow into mix chamber 850.Opening 882 allows a portion of the igniter supported on igniter holder874 to pass into oxidizer 614. Shield 852 may include openings 884.Openings 884 may provide additional oxidant to a flame in shield 852.Openings 884 may stabilize the flame in oxidizer 614 and moderate thetemperature of the flame. Spacers 886 may be positioned on shield 852 tokeep oxidizer 614 positioned in oxidant conduit 618.

In some embodiments, flame stabilizers may be added to the oxidizers.The flame stabilizers may attach the flame to the shield. The highbypass flow around the oxidizer cools the shield and protects theinternals of the oxidizer from damage enabling long term operation.FIGS. 205-210 depict various embodiments of shields 852 with flamestabilizers 888. Flame stabilizer 888 depicted in FIG. 205 is a ringsubstantially perpendicular to shield 852. The ring shown in FIG. 206 isangled away from openings 884. The rings may amount to up to about 25%annular area blockage. The rings may establish a recirculation zone nearshield 852 and away from the fuel conduit passing through the center ofthe shield.

FIG. 207 depicts an embodiment of flame stabilizer 888 in shield 852.Flame stabilizer 888 is positioned at an angle over the openings. Flamestabilizer 888 may divert incoming fluid flow through openings 884 in anupstream direction. The diverted incoming fluid may set up a flowcondition somewhat analogous to high swirl recirculation (reverse flow).One or more stagnation zones may develop where a flame front is stable.

FIG. 208 depicts an embodiment of multiple flame stabilizers 888 inshield 852. Shield 852 may have two or more sets of openings 884 alongan axial length of the shield. Rings may be positioned behind one ormore of the sets of openings 884. In some embodiments, adjacent ringsmay cause too much gas flow interference. To inhibit gas flowinterference, 3 partial rings (each ring being about ⅙ thecircumference) may be evenly spaced about the circumference instead ofone complete ring. The next set of 3 partial rings along the axiallength of heat shield may be staggered (for example, the partial ringsmay be rotated by 60° relative to the first set of 3 partial rings).FIG. 209 depicts a cross-sectional representation of shield 852 showingthe last set of openings 884 and the last set of flame stabilizers 888.Shield 852 includes spacers 886. In other embodiments, fewer or morethan 3 partial rings may be used (for example, two partial rings may beused for the first set of openings, and four partial rings may be usedfor the next set of openings). Flame stabilizers 888 may beperpendicular to shield 852, angled towards openings 884, angled awayfrom the openings (as depicted in FIG. 208) or positioned ascombinations of perpendicular and angled orientations.

FIG. 210 depicts an embodiment wherein flame stabilizers 888 aredeflector plates or baffles extending over all or portions of openings884. The portions of flame stabilizers 888 positioned over the openingsmay be cylindrical sections with the concave portions facing openings884. Flame stabilizers 888 may divert incoming fluid flow and allow theflame root area to develop around the deflectors. Some openings in theshield may not include flame stabilizers.

In some embodiments, deflectors may be positioned on the outer surfaceof the shield near to openings in the shield. The deflectors may directsome of the gas flowing through the oxidant conduit through the openingsin the shield.

In one embodiment, one or more of the oxidizers have flame stabilizersthat utilize a louvered design to direct flow into the shield. FIG. 211depicts oxidizer 614 with louvered openings 884 in shield 852. Louveredopenings 884 are in communication with the oxidant conduit. An extensionon the inside wall of shield 852 directs gas flow into shield 852 in adirection opposite to the direction of flow in the oxidant conduit. FIG.212 depicts a cross-sectional representation of a portion of shield 852with louvered opening 884. Gas with oxidant entering shield 852 may bedirected by extension 890 in a desired direction. Arrow 892 indicatesthe direction of gas flow from the oxidant conduit to the inside ofshield. Arrow 894 indicates the direction of gas flow in the oxidantconduit.

As depicted in FIGS. 204-212, shield 852 may include openings 884. Thesize and/or number of openings 884 may be varied depending on positionof the oxidizer in the oxidizer assembly to moderate the temperature andensure fuel combustion. In some embodiments, the geometry and size ofopenings 884 on a single oxidizer may be varied to compensate forchanging conditions and needs along the length of the oxidizer.

FIGS. 213-215 depict perspective views of various sectioned oxidizerembodiments. Oxidizers 614 include oxidant openings 880, mix chambers850, ignition chambers 876, and shields 852. FIGS. 213-215 depictvarious positions and sizes for openings 884 in shields 852.

In some embodiments, one or more of the openings in the shield may beangled in a non-perpendicular direction relative to the longitudinalaxis of the shield. Angled openings act as nozzles to alter the entrypath of gas into the shield. Angled openings may promote formation ofinternal low velocity recirculation zones where the reaction front canstabilize and improve the stability and reliability of the oxidizer.

The use of flame stabilizers, various sizes of openings in the shieldand/or angled openings may establish the flame zone of the oxidizerclose to the shield and far away from the fuel conduit to maximizeradial separation of the flame zone from the fuel conduit so as tominimize direct heating of the fuel conduit by the flame zone. The useof flame stabilizers, various sizes of openings in the shield and/orangled openings may also achieve lower NO_(x) emissions by effectivelyaerodynamically staging the combustion zone and creating fuel rich andlean zones. In fuel rich zones, N₂ formation (instead of NO_(x)) will befavored and aerodynamic staging will control peak temperatures andthermal NO_(x) formation. Such configurations can also enable control ofthe peak longitudinal temperature profile and flame radiation, thussuppressing overheating of the fuel conduit.

In some embodiments, fuel passes through a heated region before beingsupplied to the first oxidizer (oxidizer 868 in FIG. 197). Passing thefuel through the heated region may preheat the fuel and ensure that thefuel and additives in the fuel (for example, water to inhibit coking)are in the gas phase. Ensuring gas phase fuel may avoid plugging infirst oxidizer 868. FIG. 216 depicts an embodiment of first oxidizer 868and fuel conduit 616. Fuel conduit 616 may include sleeve 896. Fuel mayflow through sleeve 896, and a portion of the fuel may flow in theopposite direction in the annular space between the sleeve and fuelconduit 616. A portion of the fuel flowing in the annular space betweensleeve 896 and fuel conduit 616 passes through openings 878 into mixchamber 850.

In some embodiments, a portion of the fuel flowing in the annular spacebetween sleeve 896 and fuel conduit 616 passes through openings 878 intothe annular space between the fuel conduit and shield 852. Supplyingfuel into this annular space may allow flame zone 622 to extend througha significant portion of first oxidizer 868 so that the first oxidizeris able to input more heat into the formation. First oxidizer 868 may beconfigured to input more heat into the formation to help compensate forheat losses attributable to the oxidizer being the first oxidizer of theoxidizer assembly. Having first oxidizer configured to input more heatinto the formation than other oxidizers of the oxidizer assembly mayallow for a decrease in the total number of oxidizers needed in thedownhole assembly.

One or more of the oxidizers in an oxidizer assembly may be a catalyticburner. The catalytic burners may include a catalytic portion (forexample, a catalyst chamber) followed by a homogenous portion (forexample, an ignition chamber). Catalytic burners may be started late inan ignition sequence, and may ignite without igniters. Oxidant for thecatalytic burners may be sufficiently hot from upstream burners (forexample, the oxidant may be at a temperature of about 370° F. (about700° C.) if the fuel is primarily methane) so that a primary mixturewould react over the catalyst in the catalyst portion and produce enoughheat so that exiting products ignite a secondary mixture in thehomogenous portion of the oxidizer. In some embodiments, the fuel mayinclude enough hydrogen to allow the needed temperature of the oxidantto be lower. Catalysts used for this purpose may include palladium,platinum, platinum/iridium, platinum/rhodium or mixtures thereof.

FIG. 217 depicts a cross-sectional representation of catalytic burner898. Oxidant may enter mix chamber 850 through openings 880. Fuel mayenter mix chamber 850 from fuel conduit 616 through fuel openings 878′.Fuel and oxidizer may flow to catalyst chamber 902. Catalyst chamber 902contains catalyst which reacts a mixture from mix chamber 850 to producereaction products at a temperature that is sufficient to ignite fuel andoxidant. In some embodiments, the catalyst includes palladium on ahoneycomb ceramic support. The fuel and oxidant react in catalystchamber 902 to form hot reaction products. The hot reaction products maybe directed to the annular space between shield 852 and fuel conduit616. Additional fuel enters the annular space through openings 878″ infuel conduit 616. Additional oxidant enters the annular space throughopenings 884. The hot reaction products generated by catalyst 902 mayignite fuel and oxidant in autoignition zone 904. Autoignition zone 904may allow fuel and oxidant to form flame zone 622. In some embodiments,the catalytic burner includes flame stabilizers or other types of gasflow modifiers.

In some embodiments a catalytic burner may include an igniter tosimplify startup procedures. FIG. 218 depicts catalytic burner 898 thatincludes igniter 900. Igniter 900 is positioned in mix chamber 850.Catalytic burner 898 includes catalyst chamber 902. Catalyst chambercontains a catalyst that reacts a mixture from mix chamber 850 toproduce reaction products at a temperature that is sufficient to ignitefuel and oxidant. Oxidant enters mix chamber through openings 880A. Fuelenters the mix chamber from fuel line through fuel openings 878A. Thefuel input into mixture chamber 850 may be only a small fraction of thefuel input for catalytic burner 898. Igniter 900 raises the temperatureof the fuel and oxidant to combustion temperatures in pre-heat zone 906.Flame stabilizer 888 may be positioned in mixing chamber 850. Heat frompre-heat zone 906 and/or combustion products may heat additional fuelthat enters mixing chamber 850 through fuel openings 878B and additionaloxidant that enters the mixing chamber through openings 880B. Openings878B and openings 880B may be upstream of flame stabilizer 888. Theadditional fuel and oxidant are heated to a temperature sufficient tosupport reaction on catalyst 902.

Heated fuel and oxidant from mixing chamber 850 pass to catalyst 902.The fuel and oxidant react on catalyst 902 to form hot reactionproducts. The hot reaction products may be directed to heat shield 852.Additional fuel enters heat shield 852 through openings 878C in fuelconduit 616. Additional oxidant enters heat shield 852 through openings884. The hot reaction products generated by catalyst 902 may ignite fueland oxidant in autoignition zone 904. Autoignition zone 904 may allowfuel and oxidant to form main combustion zone 622. In some embodiments,the catalytic burner includes flame stabilizers or other types of gasflow modifiers.

In some embodiments, all of the oxidizers in the oxidizer assembly arecatalytic burners. In some embodiments, the first or the first severaloxidizers in the oxidizer assembly are catalytic burners. The oxidantsupplied to these burners may be at a lower temperature than subsequentburners. Using catalytic burners with igniters may stabilize the initialperformance of the first several oxidizers in the oxidizer assembly.Catalytic burners may be used in-line with other burners to reduceemissions by allowing lower flame temperatures while still havingsubstantially complete combustion.

In some embodiments, a catalytic converter may be positioned at the endof the oxidizer assembly or in the exhaust gas return. The catalyticconverter may remove unburned hydrocarbons and/or remaining NO_(x)compounds or other pollutants. The catalytic converter may benefit fromthe relatively high temperature of the exhaust gas. In some embodiments,catalytic burners in series may be integrated with coupled catalyticconverters to limit undesired emissions from the oxidizer assembly. Insome embodiments, a selectively permeable material may be used to allowcarbon dioxide or other fluids to be separated from the exhaust gas.

In one embodiment, initiation of the burner assembly may be accomplishedby initializing combustion with hydrogen and later switching to naturalgas or another fuel. The use of hydrogen-enriched fuel may suppressflame radiation and reduce heating of the fuel conduit. Oxidizers of theoxidizer assembly may be ignited using hydrogen or fuel that is highlyenriched with hydrogen. Once ignited, the composition of fuel may beadjusted to comprise natural gas and/or other fuels. The initial use ofhydrogen or hydrogen-enriched fuel widens the flammability envelopeenabling much easier startup. An initial fuel composition could then be“chased” with production gas or other more economical gases.Alternatively, the entire system could burn hydrogen. With no carbon inthe fuel, there would be no need for additional decoking methods.

FIG. 219 depicts a cross-sectional representation of an embodiment ofoxidizer 614 of oxidizer assembly 612 with the section takensubstantially perpendicular to a central axis of the oxidizer throughfuel conduit 616 that enters mix chamber 850 of the oxidizer. Oxidizer614 is positioned in oxidant conduit 618. Supports 908 position oxidizer614 in oxidant conduit 618. Supports 908 may be welded or otherwisesecured to oxidizer 614 and/or oxidant conduit 618. In some embodiments,one or more supports or spacers may be positioned in the space betweenoxidant conduit 618 and outer conduit 620 to position the oxidantconduit in the outer conduit.

Oxidant conduit 618 is positioned in outer conduit 620. Fuel conduits616 are positioned in the space between oxidant conduit 618 and outerconduit 620. In the depicted embodiment, four fuel conduits 616 areshown. More than four fuel conduits or less than four fuel conduits maybe positioned in the oxidizer assembly in other embodiments. Fuel taps910 may pass from fuel conduits 616 through oxidant conduit 618 to a mixchamber of an oxidizer. In some embodiments, each fuel conduit 616supplies a single oxidizer. In some embodiments, one fuel conduitsupplies two or more oxidizers of the oxidizer assembly. Portions or allof fuel conduits 616 and/or portions or all of fuel taps 910 may beinsulated. In some embodiments, fuel conduits 616 are positionedradially away from oxidant conduit 618 so that exhaust gas returningthrough the space between outer conduit 620 and the oxidant conduittransfers heat with the fuel conduits to limit the upper temperatureattained by the fuel conduits.

Using multiple fuel conduits may allow the supply of fuel to beinterrupted to one or more of oxidizers without adversely affecting allof the oxidizers. Multiple fuel conduits also allow for adjustment offuel mixtures supplied to the oxidizers during startup and after steadyoperation of the oxidizers is established.

Igniter supply conduits 912 may be positioned in the space betweenoxidant conduit 618 and outer conduit 620. In some embodiments, theigniter supply conduits are positioned in the oxidant conduit. Igniters900 may branch from igniter supply conduits 912 into ignition chambersof the oxidizers. In the depicted embodiment, four igniter supplyconduits 912 are shown. More than four igniter supply conduits or lessthan four igniter supply conduits may be positioned in the oxidizerassembly in other embodiments. Igniter supply conduits may be conduitsthat convey a fuel (for example, hydrogen) to a catalyst in the igniter.Igniter supply conduits may hold insulated conductors that provideelectricity to the igniters. The igniters may be glow plugs, sparkplugs, or other types of igniters that use electricity to ignite theoxidizers. In some embodiments, the igniter supply conduit is aninsulated conductor. In some embodiments, some igniter supply conduitsmay convey fuel and other igniter supply conduits of the oxidizerassembly may transmit electricity.

FIG. 220 depicts a cross-sectional representation of an embodiment ofoxidizer 614 of oxidizer assembly 612 with the section takensubstantially along the central axis of the oxidizer. Additionaloxidizers may be positioned above and/or below the oxidizer shown.Supports 908 position oxidizer 614 in oxidant conduit 618. Oxidizer 614includes mix chamber 850, ignition chamber 876 and shield 852. Oxidantconduit 618 is positioned in outer conduit 620. Fuel conduit 616 ispositioned in the space between outer conduit 620 and oxidant conduit618. One or more fuel taps 910 from fuel conduit 616 pass throughoxidant conduit 618 to mix chamber 850. Mix chamber 850 has one or moreopenings 880 that allow passage of oxidant from oxidant conduit 618 intothe mix chamber. The size and/or number of openings may be set for eachoxidizer so that the oxidizer receives an appropriate inflow into mixchamber 850. In some embodiments, the amount of flow into the mixchamber of one or more oxidizers is adjusted by a control system that isable to change the size of the openings into the mix chamber.

A mixture of fuel and oxidant passes from mix chamber 850 to ignitionchamber 876 through mixture opening 914. Mixture opening 914 may bepositioned along a central axis of oxidizer 614 as depicted in FIG. 219and FIG. 220. Positioning mixture opening 914 allows flame zone 622generated by ignited fuel mixture to be substantially axisymmetricwithin oxidizer 614. Flame zone 622 may be stable and result in theproduction of low amount of NO_(x) compounds. Flame zone 622 may havethe potential for swirl applications.

In some embodiments, igniter 900 branches from igniter supply conduit912 through oxidant conduit 618 into ignition chamber 876. Igniter 900may be used during start up of the oxidizer assembly to initiatecombustion of fuel and oxidant mixture passing through opening 914. Insome embodiments, use of the igniters is stopped after start up of theoxidizers in the oxidizer assembly. Flame zone 622 generated bycombusting the oxidant and fuel mixture may extend through ignitionchamber 876 into shield 852. Shield 852 may stabilize flame zone 622 andinhibit blow out of the flame zone by oxidant and exhaust gas flowingthrough oxidant conduit 618.

In some embodiments, one or more small oxidant conduit lines may bepositioned in the oxidizer assembly to provide additional oxidizingfluid to the oxidizers located near the end of the oxidizer assembly.Small oxidant lines may be positioned in the main oxidant conduit and/orin the space between the oxidant conduit and the outer conduit.Additional oxidizing fluid may be introduced into the exhaust andoxidizing fluid flowing through the main oxidant conduit. The additionaloxidizing fluid may result in combustion of all of the fuel supplied tothe oxidizers.

In some embodiments, oxidizers that produce a flame are used aspreheaters upstream of flameless distributed combustors. The oxidizerspreheat the oxidizing fluid and/or the fuel supplied to the flamelessdistributed combustors above a temperature of about 815° C., which isabove the auto-ignition temperature of a mixture of oxidant fluid andfuel.

The flameless distributed combustor segments may be 100 ft to 500 ft inlength. Shorter or longer flameless distributed combustor segmentlengths may also be used. The oxidizer assembly may have less than tenoxidizers. FIG. 221 depicts a schematic representation of oxidizerassembly 612 with oxidizers 614 that preheat fuel and oxidant suppliedto flameless distributed combustors 916. Oxidizers 614 may be similar tothe oxidizer depicted in FIG. 204.

Flameless distributed combustors 916 depicted in FIG. 221 may include aseries of orifices 918 in central fuel conduit 616. Orifices 918 may becritical flow orifices. Orifices 918 allow heated fuel to mix withheated oxidizing fluid so that the mixture reacts to produce additionalheat. Flameless distributed combustors 916 may operate at much lowertemperature than oxidizers 614 since no flame is present. The lowertemperature may result in the production of less NO_(x) compounds if theoxidizing fluid includes, or the fuel includes, nitrogen or nitrogencompounds.

In some embodiments, one or more additional fuel conduits may bepositioned in the space between the oxidant conduit and the outerconduit. Taps from the additional fuel conduits may pass through theoxidant conduit to provide fuel to the oxidizers and/or to the centralfuel conduit prior to one of the oxidizers.

In some embodiments, pulverized coal is the fuel used to heat thesubsurface formation. The pulverized coal may be carried into thewellbores with a non-oxidizing fluid (for example, carbon dioxide and/ornitrogen). An oxidant may be mixed with the pulverized coal at severallocations in the wellbore. The oxidant may be air, oxygen enriched airand/or other types of oxidizing fluids. Igniters located at or near themixing locations initiate oxidation of the coal and oxidant. Theigniters may be catalytic igniters, glow plugs, spark plugs, and/orelectrical heaters (for example, an insulated conductor temperaturelimited heater with heating sections located at mixing locations ofpulverized coal and oxidant) that are able to initiate oxidation of theoxidant with the pulverized coal.

The particles of the pulverized coal may be small enough to pass throughflow orifices and achieve rapid combustion in the oxidant. Thepulverized coal may have a particle size distribution from about 1micron to about 300 microns, from about 5 microns to about 150 microns,or from about 10 microns to about 100 microns. Other pulverized coalparticle size distributions may also be used. At 600° C., the time toburn the volatiles in pulverized coal with a particle size distributionfrom about 10 microns to about 100 microns may be about one second.

FIG. 222 depicts a representation of oxidizer assembly 612 in inclinedor substantially horizontal wellbore 428. FIG. 223 depicts arepresentation of downhole oxidizer assembly 612 in u-shaped wellbore428. Pulverized coal entrained in a carrier fluid may be fuel 810supplied to oxidizers 614 through fuel conduit 616. Oxidizing fluid 806may be supplied to oxidizers through oxidant conduit 618. Initially,oxidizer assembly 612 may be started using hydrogen, natural gas, orother fuel. After temperatures of oxidizers 614 are hot enough tosupport rapid pulverized coal oxidation (for example, the temperature inand adjacent to oxidizers 614 is above about 600° C.), the fuel may bechanged to pulverized coal and carrier gas. In FIG. 222, exhaust gas 808may flow through outer conduit 620 to the surface. Exhaust gas 808passing conduit 618 may help to inhibit formation of hot spots adjacentto oxidizers 614. In FIG. 223, fuel 810 and oxidizing fluid 806 mayenter u-shaped wellbore at location 664. Exhaust gas may flow to thesurface to location 668 through conduit 618. In some embodiments, afluid (for example, a molten salt or a molten metal) may be positionedin outer conduit 620 to inhibit formation of hot spots adjacent tooxidizers 614. In some embodiments, oxidant conduit 618 may bepositioned directly in u-shaped wellbore 428 without being positioned inan outer conduit.

Exhaust gas 808 from oxidizer assemblies 612 depicted in FIG. 222 andFIG. 223 may be treated to remove unreacted coal, ash, fines and/orother particles in the exhaust gas. In some embodiments, exhaust gas 808passes through one or more cyclones to remove particles from the exhaustgas. Exhaust 808 gas may be further processed to remove selectedcompounds (for example, sulfur and/or nitrogen compounds), may be usedas a drive fluid for mobilizing hydrocarbons in a formation, may besequestered in a subsurface formation, and/or may be otherwise handled.

In other embodiments, other types of downhole oxidizers are used for thesubsurface oxidation of coal to heat selected portions of the formation.FIG. 224 depicts a schematic representation of heater 920 that usespulverized coal as fuel. Heater 920 may include outer conduit 620, firstconduit 922, and second conduit 924. First conduit 922 is positioned inouter conduit 620, and second conduit 924 is positioned in the firstconduit. The end of second conduit 924 may be closed. Second conduit 924may include critical flow orifices 926. The flow rate and/or pressuresof the fluids flowing through first conduit 922 and second conduit 924may be controlled to allow for mixing of fluid from the first conduitwith fluid from the second conduit at desired locations in the firstconduit.

In an embodiment, coal and carrier gas is introduced into heater 920through first conduit 922, and oxidant is introduced through secondconduit 924. The flow rate and/or pressure in first conduit 922 andsecond conduit 924 are controlled so that the oxidant flows throughcritical flow orifices 926 into the coal and carrier gas flowing throughfirst conduit 922. Reaction of the coal and oxidant occurs in firstconduit 922. Exhaust gases pass through outer conduit 620 to thesurface. Passing the exhaust gases past the locations where oxidant andcoal are oxidized may reduce temperature variations along the length ofthe heated section of heater 920.

In an embodiment, oxidant is introduced into heater 920 through firstconduit 922, and coal and carrier gas is introduced through secondconduit 924. The flow rate and/or pressure in first conduit 922 andsecond conduit 924 are controlled so that the coal and carrier gas flowsthrough critical flow orifices 926 into the oxidant flowing throughfirst conduit 922. Reaction of the coal and oxidant occurs in firstconduit 922. Exhaust gases pass through outer conduit 620 to thesurface.

FIG. 225 depicts a schematic representation of heater 920 that usespulverized coal as fuel. Heater 920 may include outer conduit 620, firstconduit 922, and second conduit 924. First conduit 922 is positioned inouter conduit 620, and second conduit 924 is positioned in the firstconduit. The end of first conduit 922 may be sealed closed againstsecond conduit 924. Second conduit 924 may include critical floworifices 926. The flow rate and/or pressures of the fluids flowingthrough first conduit 922 and second conduit 924 may be controlled toallow for mixing of fluid from the first conduit with fluid from thesecond conduit at desired locations in the second conduit.

In an embodiment, oxidant is introduced into heater 920 through firstconduit 922, and coal and carrier gas is introduced through secondconduit 924. The flow rate and/or pressure in first conduit 922 andsecond conduit 924 are controlled so that the oxidant flows throughcritical flow orifices 926 into the coal and carrier gas flowing throughsecond conduit 924. Reaction of the coal and oxidant occurs in secondconduit 924. Reacting coal and oxidant in second conduit 924 and passingexhaust gases through outer conduit 620 to the surface may reduce theformation of hot zones adjacent to sections of heater 920 whereoxidation occurs.

In an embodiment, coal and carrier gas is introduced into heater 920through first conduit 922, and oxidant is introduced through secondconduit 924. The flow rate and/or pressure in first conduit 922 andsecond conduit 924 are controlled so that the coal and carrier gas flowsthrough critical flow orifices 926 into oxidant flowing through secondconduit 924. Reaction of the coal and oxidant occurs in second conduit924. Exhaust gases pass through outer conduit 620 to the surface.

In certain embodiments, a heater is located in a u-shaped wellbore or anl-shaped wellbore. The heater may include a heating section that ismoved during treatment of the formation. Moving the heating sectionduring treatment of the formation allows the heating section to be usedover a wide area of the formation. Using the movable heating section mayallow the heating section (and/or heater) to be significantly shorter inlength than the length of the wellbore. The shorter heating section mayreduce equipment costs and/or operating costs of the heater as comparedto a longer heating section (for example, a heating section that has alength nearly as long as the length of the wellbore).

FIG. 226 depicts an embodiment of heater 438 with heating section 1816located in a u-shaped wellbore. Heater 438 is located in opening 556. Incertain embodiments, opening 556 is a u-shaped opening with asubstantially horizontal or inclined section in hydrocarbon layer 484below overburden 482. Heater 438 may be a u-shaped heater with ends thatextend out of both legs of the wellbore. In certain embodiments, heater438 is an electrical resistance heater (a heater that provides heat byelectrical resistance heating when energized with electrical current).In some embodiments, heater 438 is an oxidation heater (for example, aheater that oxidizes (combusts) fluids to produce heat). In certainembodiments, heater 438 is a circulating fluid heater such as a moltensalt circulating heater.

In certain embodiments, heater 438 includes heating section 1816.Heating section 1816 may be the portion of heater 438 that provides heatto hydrocarbon layer 484. In certain embodiments, heating section 1816is the portion of heater 438 that has a higher electrical resistancethan the rest of the heater such that the heating section is the onlyportion of the heater that provides substantial heat output tohydrocarbon layer 484. In some embodiments, heating section 1816 is theportion of the heater that includes a downhole oxidizer (for example,downhole burner) or a plurality of downhole oxidizers. Other portions ofheater 438 may be non-heating portions of the heater (for example,lead-in or lead-out sections of the heater).

In certain embodiments, heater 438 is similar in length to thehorizontal portion of opening 556 and heating section 1816 is theportion of heater 438 shown in FIG. 226. Thus, heating section 1816 isshort in length compared to the horizontal portion of opening 556. Insome embodiments, heating section 1816 extends along the entirehorizontal portion of the heater 438 (or nearly the entire horizontalportion of the heater) and the heater is short in length compared to thehorizontal portion of opening 556 so that the heating section is shorterin length than the horizontal portion of the opening.

In some embodiments, heating section 1816 is at most ½ the length of thehorizontal portion of opening 556, at most ¼ the length of thehorizontal portion of opening 556, or at most ⅕ the length of thehorizontal portion of opening 556. For example, the horizontal portionof opening 556 in hydrocarbon layer 484 may be between about 1500 m andabout 3000 m in length and heating section 1816 may be between about 300m and about 500 m in length.

Having shorter heating section 1816 allows heat to be provided to asmall portion of hydrocarbon layer 484. The portion of hydrocarbon layer484 heated by heating section 1816 is typically first volume 1818. Firstvolume 1818 may be created around heater 438 proximate heating section1816.

In certain embodiments, heater 438 and heating section 1816 are moved toprovide heat to another portion of the formation. FIG. 227 depictsheater 438 and heating section 1816 moved to heat second volume 1820. Insome embodiments, heating section 1816 is moved by pulling heater 438from one end of opening 556 (for example, pulling the heater from theleft end of the opening, as shown in FIG. 227). In certain embodiments,heater 438 and heating section 1816 are moved further to provide heat tothird volume 1822, as shown in FIG. 228.

In certain embodiments, first volume 1818, second volume 1820, and thirdvolume 1822 are heated sequentially from the first volume to the thirdvolume. In some embodiments, portions of the volumes may overlapdepending on the moving rate of heater 438 and heating section 1816. Incertain embodiments, heater 438 and heating section 1816 are moved at acontrolled rate. For example, heater 438 and heating section 1816 may bemoved after treating first volume 1818 for a selected period of time.

Moving heater 438 and heating section 1816 at the controlled rate mayprovide controlled heating in hydrocarbon layer 484. In someembodiments, the moving rate is controlled to control the amount ofmobilization in hydrocarbon layer 484, first volume 1818, second volume1820, and/or third volume 1822. In some embodiments, the moving rate iscontrolled to control the amount of pyrolyzation in hydrocarbon layer484, first volume 1818, second volume 1820, and/or third volume 1822.The movement rate when mobilizing may be faster than the moving ratewhen pyrolyzing as more heat needs to be provided in a selected volumeof the formation to result in pyrolyzation reactions in the selectedvolume. In general, the movement rate of heater 438 and heating section1816 is controlled to achieve desired heating results for treatment ofhydrocarbon layer 484. The movement rate may be determined, for example,by assessing treatment of hydrocarbon layer 484 using simulations and/orother calculations.

In certain embodiments, heater 438 is a u-shaped heater that is moved(for example, pulled) through u-shaped opening 556, as shown in FIGS.226-228. In some embodiments, heater 438 is an L-shaped or J-shapedheater that is moved through a u-shaped opening (for example, the heatermay be shaped like the heater depicted in FIG. 228). The L-shaped orJ-shaped heater may be moved by either pulling or pushing the heaterfrom either end of the u-shaped opening.

In some embodiments, heater 438 is an L-shaped or J-shaped heater thatis moved through an L-shaped or J-shaped opening. FIGS. 229-231 depictmovement of L-shaped or J-shaped heater 438 as the heater is movedthrough opening 556 to heat first volume 1818, second volume 1820, andthird volume 1822.

FIG. 232 depicts an embodiment with two heaters 438A, 438B located inu-shaped opening 556. Heaters 438A, 438B may have heating sections1816A, 1816B, respectively. Heaters 438A, 438B and heating sections1816A, 1816B may be moved (pulled) away from each other, as shown by thearrows in FIG. 232. Moving heating sections 1816A, 1816B in oppositedirections may create heated volumes in hydrocarbon layer 484 on eachside of the middle of opening 556. In some embodiments, the heatedvolumes created by heating section 1816A may substantially mirror theheated volumes created by heating section 1816B. Thus, mirrored heatedvolumes may be sequentially created going in opposite directions fromthe middle of opening 556 by moving heating sections 1816A, 1816B awayfrom each other at a controlled rate.

In some embodiments, fast fluidized transport line systems may be usedfor subsurface heating. Fast fluidized transport line systems may havesignificantly higher overall energy efficiency as compared to usingelectrical heating. The systems may have high heat transfer efficiency.Low value fuel (for example, bitumen or pulverized coal) may be used asthe heat source. Solid transport line circulation is commercially proventechnology having relatively reliable operation.

FIG. 233 depicts a schematic representation of a portion of a fastfluidized transport line heating system. Fast fluidized transportsystems 928 may include combustion unit 930, supply conduit 932, returnconduit 934, wellbores having inlet legs 936 and outlet legs 938,replenishment line 940, treatment unit 942, oxidant supply line 944 andgas lift supply line 946. Each combustion unit 930 may provide hotfluidized material to a large number of u-shaped wellbores. For example,one combustion unit 930 may supply hot fluidized material to 20 or moreu-shaped wellbores. In some embodiments, the u-shaped wellbores areformed so that the surface footprint has long rows of inlet legs 936 andexit legs 938 of u-shaped wellbores. The exit legs and inlet legs ofthese u-shaped wellbores are located in adjacent rows. FIG. 233 depictsa portion of fast fluidized transport systems 928 adjacent to a portionof a row of inlet legs 936 and outlet legs 938. Additional fluidizedtransport systems would be located on the same row to supply all of theu-shaped wellbores on the row. Also, additional fluidized transportsystems would be positioned on adjacent rows to supply inlet legs andoutlet legs of the adjacent rows.

In some embodiments, one or more of combustion units 930 used to heatthe formation are fluidized combustors. A portion of the fluidizedmaterial from the fluidized bed reactor flows into supply conduit 932,and from the supply conduit to inlet legs 936 of u-shaped wellbores inthe formation. In some embodiments, one or more of combustion units 930used to heat the formation are furnaces, nuclear reactors, or other hightemperature heat sources. Such combustion units heat fluidized materialthat passes through the combustion units. The fluidized material flowsfrom the combustion units to supply conduit 932, and from the supplyconduit to inlet legs 936 of u-shaped wellbores in the formation.

Oxidant may be supplied to combustion unit 930 through oxidant line 948.Fuel may be supplied to combustion unit 930 through fuel line 950.Exhaust gases may be removed from combustion unit 930 through exhaustline 952. The oxidant line, fuel line and exhaust line may not be neededif the combustion unit is a nuclear reactor. If combustion unit 930 is afluidized bed combustor, fuel line 950 may spray fuel oil or other fuelinto the fluidized combustor in addition to the fuel sent to thecombustion unit contained in the fluidized material in conduit 956.Fluidized material exiting combustion unit 930 may be at a hightemperature. For example, the fluidized material may be at temperaturesfrom about 300° C. to about 1000° C., from about 500° C. to about 800°C., or from about 700° C. to about 750° C.

The u-shaped conduits in the formation may have a relatively smalldiameter. For example, the diameter of the u-shaped conduits in theformation may be less than 8 cm. Heat transfers substantially byradiation and/or conduction from the u-shaped conduits to the formation.Inlet legs 936 and/or outlet legs 938 may be insulated through theoverburden to inhibit heat transfer to the overburden. In someembodiments, the direction of flow in the u-shaped conduits is reversedperiodically to promote more uniform heating of the formation from theconduits. For example, the flow may be reversed every six months. Othertime periods before reversing the flow may be used. In some embodiments,the direction of fluidized material flow in one u-shaped conduit isopposite in direction to the flow of fluidized material in an adjacentu-shaped conduit.

The inner surfaces of the u-shaped conduits may include inserts, bafflesand/or roughened surfaces. The inserts may be liners that areperiodically replaced in the conduits. The inserts, baffles and/orroughened surfaces may increase turbulence of the fluidized material inthe conduits to increase heat transfer to the conduits. Fluidizedmaterial flowing through the u-shaped conduits may impact on theinserts, baffles and/or roughened surfaces. The impacts may transferheat kinetically to the conduits. In some embodiments, portions of theoutside surfaces of the conduits may include roughening and/orprotrusions to increase heat transfer from the conduits to theformation.

Fluidized material exiting the formation may pass from the u-shapedconduits into return conduits line 934. Return conduit 934 may directthe fluidized material to treatment unit 942. Treatment unit 942 mayinclude cyclones and/or other separation units that separate fines andexhaust gas 954 from fluidized material that may be recirculated throughfast fluidized transport system 928. In some embodiments, fluidizedmaterial that is to be recirculated is coated with bitumen or otherhydrocarbons in treatment unit 942 before being sent to combustion unit930.

Replenishment line 940 may supply fresh fluidized material to line 956returning to combustion unit 930. The fresh fluidized material maycompensate for fines and exhaust gas 954 removed in treatment unit 942.

Fluidized material in line 956 may include coal particles (for example,pulverized coal), other hydrocarbon or carbon containing material (forexample, bitumen and coke), and heat carrier particles. The heat carrierparticles may include, but are not limited to, sand, silica, ceramicparticles, waste fluidized catalytic cracking catalyst, other particlesused for heat transfer, or mixtures thereof. In some embodiments, theparticle range distribution of the fluidized material may span frombetween about 5 and 200 microns.

A portion of the hydrocarbon content in fluidized material may combustand/or pyrolyze in combustion unit 930. Fluidized material may stillhave a significant carbon (coke) and/or hydrocarbon content afterpassing through combustion unit 930. Inlet legs 936 of the u-shapedconduits in the formation may be supplied with oxidant (for example,air) through oxidant supply lines 944. The oxidant may react with thecarbon and/or hydrocarbons in the fluidized material in the u-shapedconduits. In some embodiments, the temperature of the oxidant in oxidantsupply line 944 is raised by passing through combustion unit 930 orotherwise raising the temperature of the oxidant prior to introducingthe oxidant into the u-shaped conduits. Introducing heated oxidant intothe u-shaped conduits may promote oxidation of hydrocarbons and carbonin the fluidized material. The combustion of hydrocarbons and carbon inthe fluidized material may maintain a high temperature of the fluidizedmaterial and/or generate heat that transfers to the formation. In someembodiments, oxidant from oxidant supply line 944 is supplied to outerconduits that surround portions of inlet legs 936. Valves in inlet legs936 pass oxidant from the outer conduits into the inlet legs.

Gas lifting may facilitate transport of the fluidized material in theu-shaped conduits to return conduit 934. Outlet legs 938 may bepositioned in outer conduits. Multiple valves in the outlet legs 938 mayallow entry of lift gas into the outlet legs to transport the fluidizedmaterial to return conduit 934. In some embodiments, the lift gas isair. Other gases may be used as the lift gas.

In some in situ heat treatment processes, coal, oil shale and/or biomassmay be used as a fuel to directly heat a portion of the formation. Thefuel may be provided as a solid. The fuel may be ground or otherwisesized so that the size of the chunks, pellets, or granules provides alarge surface area that facilitates combustion of the fuel. An openingmay be formed in the formation. In some embodiment, the opening is au-shaped wellbore. In some embodiments, the opening is a mine shaft ortunnel. In some embodiments, the fuel is burned as the fuel istransported on a grate through the opening in the formation. In someembodiments, the fuel is burned in a batch or semi-batch operation. Fuelis placed on a carrier and the carrier is moved to a location in theformation. The fuel is combusted, and the carrier is pulled out of theformation. Another carrier is placed in the formation with fresh fuel.Heat from the burning fuel may heat the formation. Enough fuel may beplaced on the carriers and enough oxidant may be supplied so that all orsubstantially all of the fuel is combusted before the carrier is removedfrom the formation.

Coal, oil shale and/or biomass may be significantly less expensive thanother energy sources for heating the formation (for example, electricityand/or gas). Combusting coal, oil shale and/or biomass in the formationmay improve energy efficiency and lower cost as compared with using suchfuels to produce electricity that in turn is used to heat the formation.Combustion products such as ash and other calcination products may beproduced efficiently when burning the coal, oil shale, and/or bio-massin the formation to heat the formation, as compared to the efficiency ofusing surface manufacturing techniques to generate combustion products.The combustion products may be used in cement production and/or otherindustrial processes. Gaseous combustion products such as carbon dioxidemay be used as drive fluids and/or may be sequestered in the formationor another formation.

FIG. 234 depicts a schematic representation of opening 958 that may beused to transport burning fuel through the formation. Opening 958 mayhave a relatively large bore diameter. The casing placed in the openingmay have a diameter that is greater than 20 cm, greater than 30 cm, orgreater than 50 cm. Entry leg 960 and exit leg 962 of opening 958 may bedrilled at relative shallow angles, for example, less than 45°, less30°, or less than 25°. Heat conductor shafts 964 may branch off from theopening. Heat pipes and/or heat conductive gel may be placed in the heatconductor shafts 964. Heat from heat conductor shafts 964 may transferheat away from opening 958 to other portions of the formation. Heatconducted by heat conductor shafts 964 may be sufficient to mobilize andor pyrolyze hydrocarbons in at least a portion of the formationproximate the heat conductor shafts. The heat conducted by heatconductor shafts 964 may be used in carbon dioxide compression and/orfor carbon dioxide sequestration, and/or barrier well applications. Insome embodiments, heat conductor shafts are not necessary. In someembodiments, high velocity gas (for example, pressurized carbon dioxide)may be used to move heat through the formation.

FIG. 235 depicts a top view of a portion of carrier system 966 that mayconvey burning coal, oil shale and/or biomass through the opening toheat the treatment area. FIG. 236 depicts a side view representation ofa portion of carrier system 966 used to heat the treatment areapositioned in wellbore casing 968. Carrier system 966 may include fuelcarriers 970, fuel 972, oxidant conduit 974, conveyor 976, and clean-upbin 978. In some embodiments, conveyor system 966 includes an electricalconduit and heaters 980 that branch off of the electrical conduit.Heaters 980 may be inductive heaters, temperature limited heaters, orother types of electrical heaters that provide heat to initiatecombustion of fuel 972. In some embodiments, heaters 980 travel withconveyor system 966. In some embodiments, heaters 980 are immobile.After fuel 972 begins combusting and/or after formation adjacent to theopening is hot enough to support combustion of the fuel, use of heaters980 may be reduced and/or stopped. In other embodiments, a downholeoxidizer or other type of heater may be used to initiate combustion ofthe fuel. In some embodiments, combustion initiation is only performedin the first part of the opening where heat is to be applied to theformation. After combustion initiation, the supply of oxidant keeps thefuel burning as the fuel is drawn through the formation on carriersystem 966.

In some embodiments, a removable electric heater or combustor is used toinitiate combustion of the fuel. The electric heater and/or combustormay be inserted in the formation beneath the overburden. The electricheater and/or combustor may be used to raise the temperature near theinterface between the overburden and the treatment area above anauto-ignition temperature of the fuel on the grate of a fuel carrier.The fuel on the grate may begin to combust as the fuel passes throughthe heated zone. Heat from combusting fuel heats the treatment area asthe fuel carrier moves through the treatment area. When the treatmentarea adjacent to the entrance to the treatment area rises above theauto-ignition temperature of the fuel so that fuel on the grate of afuel carrier begins combusting due to the heat at the entrance to thetreatment area, use of the electric heater and/or combustor may bereduced and/or stopped. In some embodiments, the electric heater and/orcombustor are removed from the formation.

Fuel carriers 970 may include grates 982 and ash catchers 984. Fuel 972may be positioned on top of grates 982. Fuel 972 placed on grate 982 offuel carrier 970 may be pulverized, ground or otherwise sized so thatthe average particle size of the fuel is larger than the size ofopenings through the grates. When fuel 972 burns, ash may fall throughthe openings in grates to fall on ash catchers 984. Oxidant conduit 974and heater 980 may pass through ash catchers 984.

Oxidant conduit 974 may carry an oxidant such as air, enriched air, oroxygen and a carrier fluid (for example, carbon dioxide) to fuel 972.Oxidant conduit 974 may include a number of openings that allow theoxidant to be introduced into the formation along the length of theopening that is to be heated. In some embodiments, the openings arecritical flow orifices. In some embodiments, more than one oxidantconduit 974 is placed in the opening. In some embodiments, one or moreoxidant conduits 974 enter the formation from each side of the opening.

Conveyor 976 may pull fuel carriers 970 through the opening. In someembodiments, conveyor 976 is a belt, cable and/or chain. In someembodiments, one or more powered vehicles pull and/or push the fuelcarriers through the opening. For example, a train of several fuelcarriers may be coupled to an engine that moves the fuel carriersthrough the opening. The powered vehicles may be guided by the walls ofthe opening, by one or more rails, by a cable, and/or by a computercontrol system. In some embodiments, fuel is transported pneumaticallythrough the opening. Canisters with openings are loaded with fuel.Openings in the canisters allow oxidant in and exhaust products out ofthe canisters. The canisters may be pneumatically drawn through thewellbore.

Clean-up bins 978 may be positioned periodically in carrier system 966.Clean-up bins may remove ash from the opening that does not fall intoash catchers 984. Clean-up bins 978 may have an open end thatsubstantially conforms to the bottom of casing 968.

Temperature sensors in the opening may provide information ontemperature along the opening to a control system. Speed of the carriersystem, position, loading patterns of the grates, oxidant deliverythrough the oxidant conduit and/or other adjustable parameters may bechanged by the control system to control the heating of the treatmentarea.

In some embodiments, the fuel carriers are drawn in a loop through twoor more openings in the formation to form a circuit. FIG. 237 depicts anaerial view representation of a system that heats the treatment areausing burning fuel that is moved through the treatment area. The fuelcarriers may enter leg 960 of opening 958, and exit through leg 962. Thefuel carriers may be drawn through supply station 986 by conveyor 976.Supply station may include machinery that interacts with conveyor 976 tomove the fuel carriers along the loop. In supply station 986, the fuelcarriers may be re-supplied with fuel, inspected, repaired, and/orcleaned of ash. Ash may be sent to a treatment facility or disposalsite. The fuel carriers may leave supply station 986 and enter leg 960′of opening 958′. The fuel carriers travels through opening 958′ andexits through leg 962′. Combustion of fuel on the fuel carriers in theopening may heat the formation adjacent to the opening. The fuelcarriers may enter supply station 986′. At supply station 986′, the fuelcarriers may be re-supplied with fuel, inspected, repaired, and/orcleaned of ash. Supply station 986′ may also include machinery thatinteracts with conveyor 976 to move the fuel carriers along the loop.

Exhaust conduits 988 may convey exhaust from the burned fuel to exhausttreatment system 990. Exhaust treatment system 990 may treat exhaust toremove noxious compounds from the exhaust (for example, NO_(x) andCO_(x)). In some embodiments, exhaust treatment system 990 may include acatalytic converter system. Treated exhaust may be used for otherprocesses (for example, the treated exhaust may be used as a drivefluid) and/or the treated exhaust may be sequestered.

In some in situ heat treatment process embodiments, a circulation systemis used to heat the formation. The circulation system may be a closedloop circulation system. FIG. 238 depicts a schematic representation ofa system for heating a formation using a circulation system. The systemmay be used to heat hydrocarbons that are relatively deep in the groundand that are in formations that are relatively large in extent. In someembodiments, the hydrocarbons may be 100 m, 200 m, 300 m or more belowthe surface. The circulation system may also be used to heathydrocarbons that are not as deep in the ground. The hydrocarbons may bein formations that extend lengthwise up to 1000 m, 3000 m, 5000 m, ormore. The heaters of the circulation system may be positioned relativeto adjacent heaters so that superposition of heat between heaters of thecirculation system allows the temperature of the formation to be raisedat least above the boiling point of aqueous formation fluid in theformation.

In some embodiments, heaters 802 may be formed in the formation bydrilling a first wellbore and then drilling a second wellbore thatconnects with the first wellbore. Piping may be positioned in theu-shaped wellbore to form u-shaped heater 802. Heaters 802 are connectedto heat transfer fluid circulation system 992 by piping. In someembodiments, the heaters are positioned in triangular patterns. In otherembodiments, other patterns are used. Production wells and/or injectionwells may also be formed in the formation. The production wells and/orthe injection wells may have long substantially horizontal sectionssimilar to the heating portions of heaters 802, or the production wellsand/or injection wells may otherwise oriented (for example, the wellsmay be vertically oriented wells, or wells that include one or moreslanted portions).

In some embodiments vertical, slanted or L-shaped wells heater wells maybe used instead of u-shaped wells that have an entrance at a firstlocation and an exit at another location. FIG. 239 depicts L-shapedheater 802. Heater 802 may include heat transfer fluid circulationsystem 992, inlet conduit 1824, and outlet conduit 1826. Heat transferfluid circulation system 992 may supply heat transfer fluid to multipleheaters. Heat transfer fluid from heat transfer fluid circulation system992 may flow down inlet conduit 1824 and back up outlet conduit 1826.Inlet conduit 1824 and outlet conduit 1826 may be insulated throughoverburden. In some embodiments, inlet conduit 1824 is insulated throughoverburden 482 and hydrocarbon containing layer 484 to inhibit undesiredheat transfer between ingoing and outgoing heat transfer fluid.

In some embodiments wellbore 428 adjacent to overburden 482 is largerthan the wellbore adjacent to hydrocarbon containing layer 484. Having alarger opening adjacent to the overburden may allow for accommodation ofinsulation used to separately insulate inlet conduit 1824 and outletconduit 1826. Some heat loss to the overburden from the return flow maynot cause much of an efficiency impact, especially when the heattransfer fluid is a molten salt or other fluid that needs to be heatedto remain a liquid. The heated overburden adjacent to heater 802 maymaintain the heat transfer fluid as a liquid for a significant timeshould circulation of heat transfer fluid stop. Allowing some heat totransfer to overburden 482 may eliminate the need for expensiveinsulation systems between outlet conduit 1826 and the overburden. Insome embodiments, insulative cement is used between overburden 482 andoutlet conduit 1826.

For vertical, slanted or L-shaped heaters, the wellbores may be drilledlonger than needed to accommodate the non-heated heaters. Thermalexpansion of the heaters may cause portions of the heaters to move intothe extra length of the wellbores to accommodate thermal expansion ofthe heaters. For L-shaped heaters, remaining drilling fluid and/orformation fluid in the wellbore may facilitate movement of the heaterdeeper into the wellbore as the heater expands during preheating and/orheating with heat transfer fluid.

For a vertical or slanted wellbore, the wellbore may be drilled deeperthan needed to accommodate the inserted heater. When the heater ispreheated and/or heated with the heat transfer fluid used to heat thetreatment area, the heater may expand into the extra depth of thewellbore.

FIG. 240 depicts a schematic representation of an embodiment of aportion of vertical heater 802. Heat transfer fluid circulation system992 may provide heat transfer fluid to inlet conduit 1824 of heater 802.Heat transfer fluid circulation system 992 may receive heat transferfluid from outlet conduit heat 1826. Inlet conduit 1824 may be securedto outlet conduit 1826 by welds 1922. Inlet conduit 1824 may includeinsulating sleeve 1836. Insulating sleeve 1836 may be formed of a numberof sections. Each section of insulating sleeve 1836 for inlet conduit1824 is able to accommodate the thermal expansion caused by thetemperature difference between the temperature of the inlet conduit andthe temperature outside of the insulating sleeve. Change in length ofinlet conduit 1824 and insulation sleeve 1836 due to thermal expansionis accommodated in outlet conduit 1826.

Outlet conduit 1826 may include insulating sleeve 1836′. Insulatingsleeve 1836′ may end near treatment area 1028. In some embodiments,insulating sleeve 1836′ is installed using a coiled tubing rig. An upperfirst portion of insulating sleeve 1836′ may be secured to outletconduit 1826 above or near wellhead 476 by weld 1922. Heater 802 may besupported in wellhead 476 by a coupling between the outer support memberof insulating sleeve 1836′ and the wellhead. The outer support member ofinsulating sleeve 1836′ may have sufficient strength to support heater802. A separate lower second portion of insulating sleeve 1836′ may besecured to outlet conduit 1826 by welds 1922 or other types of sealsthat can withstand high temperature below packer 1924. Welds 1922between insulating sleeve 1836′ and outlet conduit 1826 may inhibitformation fluid from passing between the insulating sleeve and theoutlet conduit. During heating, thermal expansion causing by thetemperature difference between the outer relatively cool surface ofinsulating sleeve 1836′ and the inner surface of the insulating sleeve1836′ may cause separation between the first portion of the insulatingsleeve 1836′ and the second portion of the insulating sleeve. Theseparation may occur adjacent to the overburden portion of heater 802above packer 1924. Heat loss to the overburden may not cause much of anenergy efficiency impact for the system. Insulating cement betweencasing 564 and the formation may inhibit heat loss to the formation andimprove the overall energy efficiency of the system.

Packer 1924 may be a polished bore receptacle. Packer 1924 may be fixedto casing 564 of the wellbore 428. In some embodiments, packer 1924 is1000 m or more below the surface. Packer 1924 may be located at a depthabove 1000 m if desired. Packer 1924 may inhibit formation fluid fromflowing from the heated portion of the formation up the wellbore towellhead 476. Packer 1924 may allow movement of insulating sleeve 1836′downwards to accommodate thermal expansion of heater 802.

Wellhead 476 may include fixed seal 1926. Fixed seal 1926 may be asecond seal that inhibits formation fluid from reaching the surfacethrough wellbore 428 of heater 802.

FIG. 241 depicts vertical heater 802 in wellbore 428. The embodimentdepicted in FIG. 241 is similar to the embodiment depicted in FIG. 240,but fixed seal 1926 is located adjacent to overburden 482, and slidingseal 1852 is located in wellhead 476. The portion of insulating sleeve1836′ from fixed sleeve to wellhead 476 is able to expand upward out ofthe wellhead to accommodate thermal expansion. The portion of heaterlocated below fixed seal 1926 is able to expand into the excess lengthof wellbore 428 to accommodate thermal expansion.

In some embodiments, the heater may include a flow switcher. The flowswitcher may allow the heat transfer fluid from the circulation systemto flow down through the overburden in the inner conduit of the heater.The return flow from the heater may flow upwards through the annularregion between the inner conduit and the outer conduit. The flowswitcher may change the downward flow from the inner conduit to theannular region between the outer conduit and the inner conduit. The flowswitcher may also change the upward flow from the inner conduit to theannular region. The use of the flow switcher may allow the heater tooperate at a higher temperature adjacent to the treatment area withoutincreasing the initial temperature of the heat transfer fluid providedto the heaters.

For vertical, slanted or L-shaped heaters where the flow of heattransfer fluid is directed down the inlet conduit and returns throughthe annular region between the inlet conduit and the outlet conduit, atemperature gradient may form in the heater with the hottest portionbeing located at a distal end of the heater. For L-shaped heaters,horizontal portions of a set of first heaters may be alternated with thehorizontal portions of a second set of heaters. The hottest portionsused to heat the formation of the first set of heaters may be adjacentto the coldest portions used to heat the formation of the second set ofheaters, while the hottest portions used to heat the formation of thesecond set of heaters are adjacent to the coldest portions used to heatthe formation of the first set of heaters. For vertical or slantedheaters, flow switchers in selected heaters may allow the heaters to bearranged with the hottest portions used to heat the formation of firstheaters adjacent to coldest portions used to heat the formation ofsecond heaters. Having hottest portions used to heat the formation ofthe first set of heaters that are adjacent to coldest portions used toheat the formation of the second set of heaters may allow for moreuniform heating of the formation.

Treatment areas in a formation may be treated in patterns. FIG. 242depicts a schematic representation of treatment area 1028 treated usinga corridor pattern system. Heat transfer circulation systems 992, 992′may be positioned on each side of treatment area 1028. Inlet wellheads1828 and outlet wellheads 1830 of subsurface heaters 802 may bepositioned in rows along each side of the treatment area. Although onerow of wellheads is depicted on each side of treatment area 1028,sufficient wells may be formed in the formation so that heaters 802 inthe formation form a three dimensional pattern in the treatment areawith well spacings that allow for superposition of heat from adjacentheaters. Hot heat transfer fluid from circulation system 992 flowsthrough manifolds to inlet wellheads 1828 on the first side of treatmentarea 1028. The heat transfer fluid passes through heaters 802 to outletwellbores 1830 on the second side of treatment area 1028. Heat istransferred from the heat transfer fluid to treatment area 1028 as theheat transfer fluid travels from inlet wellheads 1828 to outletwellheads 1830. The heat transfer fluid passes from outlet wellheads1830 through manifolds to heat transfer fluid circulation system 992′ onthe second side of treatment area 1028. Additional corridor patternsabove, below and/or to the sides of treatment area 1028 may processedduring or after in heat situ treatment of treatment area 1028.

FIG. 243 depicts a schematic representation of treatment area 1028treated using a radial pattern system. Treatment area 1028 may be anannular region located between heater inlets and heater outlets. Centralheat transfer fluid circulation systems 992 may be positioned near to oron a first side of treatment area 1028. Outer heat transfer fluidcirculation systems 992′ may be positioned near to or on a second sideof treatment area 1028. Inlet wellheads 1828 and outlet wellheads 1830of subsurface heaters 802 may be positioned in rings along each side ofthe treatment area. Although one ring of inlet wellheads 1828 and onering of outlet wellheads 1830 is depicted on each side of treatment area1028, sufficient wells may be formed in the formation so that heaters802 in the formation form a three-dimensional pattern in the treatmentarea with well spacings that allow for superposition of heat fromadjacent heaters. Hot heat transfer fluid from central heat transferfluid circulation systems 992 flows through manifolds to inlet wellheadson the first side of treatment area 1028. The heat transfer fluid passesthrough heaters 802 to outlet wellbores 1830 on the second side oftreatment area 1028. Heat is transferred from the heat transfer fluid tothe treatment area as the heat transfer fluid travels from inletwellheads 1828 to outlet wellheads 1830. The heat transfer fluid passesfrom outlet wellheads 1830 through manifolds to outer heat transferfluid circulation systems 992′ on the second side of treatment area1028. Heat transfer fluid heated by outer heat transfer fluidcirculation systems 992′ passes through manifolds to inlet wellheads1828. The heat transfer fluid passes through heaters 802 to outletwellheads 1830 on the first side of treatment area 1028. The heattransfer fluid flows through manifolds to central heat transfer fluidcirculation systems 992. Additional radial patterns may be formed atother locations in the formation.

In some embodiments, only a portion of the ring of treatment area istreated. In some embodiments, the entire ring of the treatment area, ora portion of the treatment area is treated in sections. For example,central circulation system or central circulation systems 992 may supplyheat transfer fluid to a first set of heaters. The first set of heaters,along with a second set of return heaters may treat a first section ofabout one eighth (or 45°) of the treatment area. Other section sizes maybe chosen. The heat transfer fluid from central circulation system orcentral circulation systems 992 may be received by one or more outercirculation systems 992′. One or more outer circulation systems 992′ mayprovide heat transfer fluid return to central circulation system orcentral circulation systems 992. After completion of heating of thefirst section of treatment area, an adjacent section to the firstsection or another section of the treatment area not adjacent to thefirst section may be treated. The outer circulation system may be mobileso that the outer circulation system can be used to treat differentsections of the treatment area. In some embodiments, one or moreproduction wells for a particular section may be used to produceformation fluid during the treatment of another section.

Due to the radial layout of heaters 802, the heater density and/or heatinput per volume of formation increases from the second side oftreatment area 1028 towards the first side of the treatment area. Theheater density and/or heat input per volume change may establish atemperature gradient through treatment area 1028 with the averagetemperature of the treatment area increasing from the second side of thetreatment area towards the first side of the treatment area. Forexample, the average temperature near the first side of treatment area1028 may be about 300° C. to about 350° C. while the average temperaturenear the second side may be about 180° C. to about 220° C. The highertemperature near the first side of treatment area 1028 may result in themobilization of hydrocarbons towards the second side of the treatmentarea.

FIG. 244 depicts a plan view of an embodiment of wellbore openings on afirst side of treatment area 1028. Heat transfer fluid entries 1002 intothe formation alternate with heat transfer fluid exits 1004. Alternatingheat transfer fluid entries 1002 with heat transfer fluid exits 1004 mayallow for more uniform heating of the hydrocarbons in formation 524.

In some embodiments, piping and surface facilities for the circulationsystem may allow the direction of heat transfer fluid flow through theformation to be changed. Changing the direction of heat transfer fluidflow through the formation allows each end of a u-shaped wellbore toinitially receive the heat transfer fluid at the hottest temperature ofthe heat transfer fluid for a period of time, which may result in moreuniform heating of the formation. The direction of heat transfer fluidmay be changed at desired time intervals. The desired time interval maybe about a year, about six months, about three months, about two monthsor any other desired time interval.

Gas at high pressure may be used as the heat transfer fluid in thecirculation system. In some embodiments, the heat transfer fluid iscarbon dioxide. Carbon dioxide is chemically stable at the requiredtemperatures and pressures and has a relatively high molecular weightthat results in a high volumetric heat capacity. Other fluids such assteam, air, helium and/or nitrogen may also be used. The pressure of theheat transfer fluid entering the formation may be 3000 kPa or higher.The use of high pressure heat transfer fluid allows the heat transferfluid to have a greater density, and therefore a greater capacity totransfer heat. Also, the pressure drop across the heaters is less for asystem where the heat transfer fluid enters the heaters at a firstpressure for a given mass flow rate than when the heat transfer fluidenters the heaters at a second pressure at the same mass flow rate whenthe first pressure is greater than the second pressure.

In some embodiments, a liquid heat transfer fluid is used as the heattransfer fluid. The liquid heat transfer fluid may be natural orsynthetic oil, molten metal, molten salt, or other type of hightemperature heat transfer fluid. A liquid heat transfer fluid may allowfor smaller diameter piping and reduced pumping/compression costs. Insome embodiments, the piping is made of a material resistant tocorrosion by the liquid heat transfer fluid. In some embodiments, thepiping is lined with a material that is resistant to corrosion by theliquid heat transfer fluid. For example, if the heat transfer fluid is amolten fluoride salt, the piping may include a 10 mil thick nickelliner. The piping may be formed by roll bonding a nickel strip onto astrip of the piping material (for example, stainless steel), rolling thecomposite strip, and longitudinally welding the composite strip to formthe piping. Other techniques may also be used. Corrosion of nickel bythe molten fluoride salt may be less than 1 mil per year at atemperature of about 840° C.

As depicted in FIG. 238, heat transfer fluid circulation system 992 mayinclude heat supply 994, first heat exchanger 996, second heat exchanger998, and fluid movers 1000. Heat supply 994 heats the heat transferfluid to a high temperature. Heat supply 994 may be a furnace, solarcollector, chemical reactor, nuclear reactor, fuel cell, and/or otherhigh temperature source able to supply heat to the heat transfer fluid.If the heat transfer fluid is a gas, fluid movers 1000 may becompressors. If the heat transfer fluid is a liquid, fluid movers 1000may be pumps.

After exiting formation 524, the heat transfer fluid passes throughfirst heat exchanger 996 and second heat exchanger 998 to fluid movers1000. First heat exchanger 996 transfers heat between heat transferfluid exiting formation 524 and heat transfer fluid exiting fluid movers1000 to raise the temperature of the heat transfer fluid that entersheat supply 994 and reduce the temperature of the fluid exitingformation 524. Second heat exchanger 998 further reduces the temperatureof the heat transfer fluid. In some embodiments, second heat exchanger998 includes or is a storage tank for the heat transfer fluid.

Heat transfer fluid passes from second heat exchanger 998 to fluidmovers 1000. Fluid movers 1000 may be located before heat supply 994 sothat the fluid movers do not have to operate at a high temperature.

In an embodiment, the heat transfer fluid is carbon dioxide. Heat supply994 is a furnace that heats the heat transfer fluid to a temperature ina range from about 700° C. to about 920° C., from about 770° C. to about870° C., or from about 800° C. to about 850° C. In an embodiment, heatsupply 994 heats the heat transfer fluid to a temperature of about 820°C. The heat transfer fluid flows from heat supply 994 to heaters 802.Heat transfers from heaters 802 to formation 524 adjacent to theheaters. The temperature of the heat transfer fluid exiting formation524 may be in a range from about 350° C. to about 580° C., from about400° C. to about 530° C., or from about 450° C. to about 500° C. In anembodiment, the temperature of the heat transfer fluid exiting formation524 is about 480° C. The metallurgy of the piping used to form heattransfer fluid circulation system 992 may be varied to significantlyreduce costs of the piping. High temperature steel may be used from heatsupply 994 to a point where the temperature is sufficiently low so thatless expensive steel can be used from that point to first heat exchanger996. Several different steel grades may be used to form the piping ofheat transfer fluid circulation system 992.

In an embodiment, the heat transfer fluid is a molten salt, such assolar salt. Heat supply is a furnace that heats the heat transfer fluidto a temperature of about 560° C. The return temperature of the heattransfer fluid may be from about 350° C. to about 450° C. Piping fromheat transfer fluid circulation system 992 may be insulated and/or heattraced to facilitate startup and to ensure fluid flow.

In some embodiments, the diameter of the conduit through which the heattransfer fluid flows in overburden 482 may be smaller than the diameterof the conduit through the treatment area. For example, the diameter ofthe pipe in the overburden may be about 3 inches, and the diameter ofthe piping adjacent to the treatment area may be about 5 inches. Thesmaller diameter pipe through overburden 482 may allow for less heattransfer to the overburden. Reducing the amount of heat transfer tooverburden 482 reduces the amount of cooling of the heat transfer fluidsupplied to the conduit adjacent to hydrocarbon layer 484. The increasedheat transfer in the smaller diameter pipe due to increased velocity ofheat transfer fluid through the small diameter pipe is offset by thesmaller surface area of the smaller diameter pipe and the decrease inresidence time of the heat transfer fluid in the smaller diameter pipe.

Heat transfer fluid from heat supply 994 of heat transfer fluidcirculation system 992 passes through overburden 482 of formation 524 tohydrocarbon layer 484. Portions of heaters 802 extending throughoverburden 482 may be insulated. In some embodiments, the insulation orpart of the insulation is a polyimide insulating material. Inletportions of heaters 802 in hydrocarbon layer 484 may have taperinginsulation to reduce overheating of the hydrocarbon layer near the inletof the heater into the hydrocarbon layer.

The overburden section may be insulated to prevent or inhibit heat lossinto non-hydrocarbon bearing zones of the formation. Thermal insulationmay be provided by a conduit-in-conduit design. The heat transfer fluidflows through the inner conduit. Insulation fills the space between theinner conduit and outer conduit. An effective insulation may be acombination of metal foil to inhibit radiative heat loss and microporoussilica powder to inhibit conductive heat loss. Reducing the pressure inthe space between the inner conduit and the outer conduit by pulling avacuum during assembly and/or with getters may further reduce heatlosses when using the conduit-in-conduit configuration. To account forthe differential thermal expansion of the inner conduit and the outerconduit, the inner conduit may be pre-stressed or made of a materialwith low thermal expansion (for example, Invar). The insulatedconduit-in-conduit may be installed continuously in conjunction withcoiled tubing installation. Insulated conduit-in-conduit systems may beavailable from Industrial Thermo Polymers Limited (Ontario, Canada), andOil Tech Services, Inc. (Houston, Tex., U.S.A.). Other effectiveinsulation materials include, but are not limited to, ceramic blankets,foam cements, cements with low thermal conductivity aggregates such asvermiculite, Izoflex insulation, and aerogel/glass-fiber composites suchas those provided by Aspen Aerogels (Northborough, Mass.).

FIG. 245 depicts a cross-sectional view of an embodiment of overburdeninsulation. Insulating cement 1832 may be placed between casing 564 andformation 524. Insulating cement 1832 may also be placed between heattransfer fluid conduit 1834 and casing 564.

FIG. 246 depicts a cross-sectional view of an alternate embodiment ofoverburden insulation that includes insulating sleeve 1836 around heattransfer fluid conduit 1834. Insulating sleeve 1836 may include anaerogel. Gap 1838 may be located between insulating sleeve 1836 andcasing 564. The emissivities of insulating sleeve 1836 and casing 564may be low to inhibit radiative heat transfer. A non-reactive gas may beplaced in gap 1838 between insulating sleeve 1836 and casing 564. Gas ingap 1838 may limit conductive heat transfer between insulating sleeve1836 and casing 564. In some embodiments, a vacuum may be drawn andmaintained in gap 1838. Insulating cement 1832 may be placed betweencasing 564 and formation 524. Insulating sleeve 1836 may have asignificantly smaller thermal conductivity value than the thermalconductivity value of insulating cement. The insulation provided by theinsulation depicted in FIG. 246 may be significantly better than theinsulation provided by the insulating depicted in FIG. 245.

FIG. 247 depicts a cross-sectional view of an alternate embodiment ofoverburden insulation with insulating sleeve 1836 around heat transferfluid conduit 1834, vacuum gap 1840 between the insulating sleeve andconduit 1842, and gap 1838 between the conduit and casing 564.Insulating cement 1832 may be placed between casing 564 and formation524. A non-reactive gas may be placed in gap 1838 between conduit 1842and casing 564. In some embodiments, a vacuum may be drawn andmaintained in gap 1838. A vacuum may be drawn and maintained in vacuumgap 1840 between insulating sleeve 1836 and conduit 1842. Insulatingsleeve 1836 may include layers of insulating material separated by foil1844. The insulation material may be aerogel. The layers of insulatingmaterial separated by foil 1844 may provide significant insulationaround heat transfer fluid conduit 1834. Vacuum gap 1840 may inhibitradiative, convective and conductive heat transfer from insulatingsleeve 1836 to conduit 1842. A non-reactive gas may be placed in gap1838. The emissivities of conduit 1842 and casing 564 may be low toinhibit radiative heat transfer from the conduit to the casing. Theinsulation provided by the insulation depicted in FIG. 247 may besignificantly better than the insulation provided by the insulatingdepicted in FIG. 246.

When heat transfer fluid is circulated through piping in the formationto heat the formation, the heat of the heat transfer fluid will causechanges in the piping. The heat of the piping may significantly reducethe strength of the piping since Young's modulus and other strengthcharacteristics vary with temperature. The high temperatures of thepiping may raise creep concerns, may cause buckling conditions, and maymove the piping from the elastic deformation region to the plasticdeformation region.

Heating the piping will cause thermal expansion of the piping. For longheaters placed in the wellbore, the heater may expand 20 m or more. Insome embodiments, the horizontal portion of the heater is cemented inthe formation with thermally conductive cement. Care may need to betaken to ensure that there are no significant gaps in the cement so thatpiping does not expand in the gaps and fail. Thermal expansion of thepiping may cause ripples in the pipe and/or an increase in the wallthickness of the pipe.

For long heaters with gradual bend radii (for example, about 10° of bendper 30 m), thermal expansion of the piping may be accommodated in theoverburden or above surface. After thermal expansion is completed, theposition of the heaters relative to the wellheads may be secured. Whenheating is finished and the formation is cooled, the position of theheaters may be unsecured so that thermal contraction of the heaters doesnot destroy the heaters.

FIGS. 248-255 depict schematic representations of various methods foraccommodating thermal expansion. In some embodiments, change in lengthof the heater due to thermal expansion may be accommodated above thewellhead. After significant changes in the length of the heater due tothermal expansion cease because the heater is hot, the heater positionrelative to the wellhead may be fixed. The heater position relative tothe wellhead may remain fixed until the end of heating of the formation.After heating is ended, the position of the heater relative to thewellhead may be freed so that the heater is able to accommodate thermalcontraction as the heater cools.

FIG. 248 depicts a representation of bellows 1846. Length L of bellows1846 may change to accommodate thermal expansion and/or contraction ofpiping 1848. Bellows 1846 may be located subsurface or above thesurface.

FIG. 249 depicts a representation of piping 1848 with expansion loop1850 above wellhead 476. Sliding seals in the wellhead 476, stuffingboxes, or other pressure control equipment of the wellhead allow piping1848 to move relative to casing 564. Expansion of piping 1848 isaccommodated in one or more expansion loops 1850. In some embodiments,expansion is accommodated by coiling the portion of the heater exitingthe formation on a spool using a coiled tubing rig.

FIG. 250 depicts piping in a portion of piping 1848 in overburden 482after thermal expansion of the piping has occurred. Casing 564 has alarge diameter. Insulating cement 1832 may be between underburden 482and casing 564. Thermal expansion of piping 1848 is allowed to causehelical or sinusoidal buckling of the piping. The helical or sinusoidalbuckling of piping 1848 accommodates the thermal expansion of thepiping, including the horizontal piping adjacent to the treatment areabeing heated. As depicted in FIG. 251, piping 1848 may be more than oneconduit positioned in large diameter casing 564. Having piping 1848 asmultiple conduits allows for accommodation of thermal expansion of allof the piping in the formation without significantly increasing thepressure drop of the fluid flowing through piping in overburden 482.

In some embodiments, thermal expansion of subsurface piping istranslated up to the wellhead. Expansion may be accommodated by one ormore sliding seals at the wellhead. The seals may include Grafoil®gaskets, Stellite® gaskets, and/or Nitronic gaskets.

FIG. 252 depicts a representation of wellhead 476 with sliding seal1852, stuffing box and/or other pressure control equipment. Circulatedfluid may pass through conduit 1834. Conduit 1834 may be at leastpartially surrounded by insulated conduit 1836. The use of insulatedconduit 1836 may obviate the need for a high temperature sliding sealand the need to seal against the heat transfer fluid. Expansion ofconduit 1834 may be handled at the surface with expansion loops,bellows, coiled tubing rigs, and/or sliding joints. In some embodiments,packers 1854 between insulated conduit 1836 and casing 564 seal thewellbore against formation pressure. Packers 1854 may be inflatablepackers and/or polished bore receptacles.

In some embodiments, thermal expansion of subsurface piping is handledat the surface with a slip joint that allows the heat transfer fluidconduit expand out of the formation to accommodate thermal expansion.Hot heat transfer fluid may pass from a fixed conduit into the heattransfer fluid conduit in the formation. Return heat transfer fluid fromthe formation may pass from the heat transfer fluid conduit into a fixedconduit. A sliding seal between the fixed conduit and the piping in theformation, and a sliding seal between the wellhead and the piping in theformation, may accommodate expansion of the heat transfer fluid conduit.FIG. 253 depicts a representation of a system where heat transfer fluidin conduit 1834 is transferred to or from fixed conduit 1856. Insulatingsleeve 1836 may surround conduit 1834. Sliding seal 1852 may be betweeninsulated sleeve 1836 and wellhead 476. Packers between insulatingsleeve 1836 and casing 564 may seal the wellbore against formationpressure. Heat transfer fluid seals 1858 may be positioned between aportion of fixed conduit 1856 and conduit 1834. Heat transfer fluidseals may be secured to fixed conduit 1856. The resulting slip jointallows insulating sleeve 1836 and conduit 1834 to move relative towellhead 476 to accommodate thermal expansion of the piping positionedin the formation. Conduit 1834 is able to move relative to fixed conduit1856 in order to accommodate thermal expansion. Heat transfer fluidseals 1858 may be uninsulated and spatially separated from the flowingheat transfer fluid to maintain the heat transfer fluid seals atrelatively low temperatures.

In some embodiments, thermal expansion may be handled at the surfacewith a slip joint where the heat transfer fluid conduit is free to moveand the fixed conduit is part of the wellhead. FIG. 254 depicts arepresentation of system where fixed conduit 1856 is secured to wellhead476. Fixed conduit 1856 may include insulating sleeve 1836. Heattransfer fluid seals 1858 may be coupled to an upper portion of conduit1834. Heat transfer fluid seals 1858 may be uninsulated and spatiallyseparated from the flowing heat transfer fluid to maintain the heattransfer fluid seals at relatively low temperatures. Conduit 1834 isable to move relative to fixed conduit 1856 without the need for asliding seal in wellhead 476.

In an embodiment, lift systems are coupled to the piping of a heaterthat extends out of the formation. The lift systems may lift portions ofthe heater out of the formation to accommodate thermal expansion. FIG.255 depicts a representation of u-shaped wellbore 428 with heater 802positioned in the wellbore. Wellbore 428 may include casings 564 andlower seals 1860. Heater 802 may include insulated portions 1862, andheater portion 1864 adjacent to treatment area 1028. Moving seals 1858may be coupled to an upper portion of heater 802. Lifting systems 1866may be coupled to insulated portions 1862 above wellheads 476. Anon-reactive gas (for example, nitrogen and/or carbon dioxide) may beintroduced in subsurface annular region 1868 between casings 564 andinsulated portions 1862 to inhibit gaseous formation fluid from risingto wellhead 476 and to provide an insulating gas blanket. Insulatedportions 1862 may be conduit-in-conduits with the heat transfer fluid ofthe circulation system flowing through the inner conduit. The outerconduit of each insulated portion 1862 may be at a significantly lowertemperature than the inner conduit. The lower temperature of the outerconduit allows the outer conduits to be used as a load bearing memberfor lifting heater 802. Differential expansion between the outer pipeand the inner pipe may be mitigated by internal bellows and/or bysliding seals.

Lifting systems 1866 may include hydraulic lifters, powered coiledtubing rigs, and/or counterweight systems capable of supporting heater802 and moving insulated portions 1862 into or out of the formation.When lifting systems 1866 include hydraulic lifters, the outer conduitsof insulated portions 1862 may be kept cool at the hydraulic lifters bydedicated slick transition joints. The hydraulic lifters may include twosets of slips. The first set of slips may be coupled to the heater. Thehydraulic lifters may maintain a constant pressure against the heaterfor the full stroke of the hydraulic cylinder. The second set of slipsmay periodically be set against the outer conduit while the stroke ofthe hydraulic cylinder is reset. Lifting systems 1866 may also includestrain gauges and control systems. The strain gauges may be attached tothe outer conduit of insulated portions 1862, or the strain gauges maybe attached to the inner conduits of the insulated portions below theinsulation. Attaching the strain gauges to the outer conduit may beeasier and the attachment may be more reliable.

Before heating begins, set points for the control systems may beestablished by using lifting systems 1866 to lift heater 802 so thatportions of the heater contact casing 564 in the bend portions ofwellbore 428. The strain when heater 802 is lifted may be used as theset point for the control system. In other embodiments, the set pointmay be chosen in a different manner. When heating begins, heater portion1864 will begin expanding and some of the heater section will advancehorizontally. If the expansion forces portions of heater 802 againstcasing 564, the weight of the heater will be supported at the contactpoints of insulated portions 1862 and the casing. The strain measured bylifting system 1866 will go towards zero. Additional thermal expansionmay cause heater 802 to buckle and fail. Instead of allowing heater 802to press against casing 564, hydraulic lifters of lifting systems 1866may move sections of insulated portions 1862 upwards and out of theformation to keep the heater against the top of the casing. The controlsystems of lifting systems 1866 may lift heater 802 to maintain thestrain measured by the strain gauges near the set point value. Liftingsystem 1866 may also be used to reintroduce insulated portions 1862 intothe formation when the formation cools to avoid damage to heater 802during thermal contraction.

Thermal expansion of the heater may be complete in a relatively shorttime frame. In some embodiments, the position of the heater is fixedrelative to the wellbore after thermal expansion is completed. Thelifting systems may be removed from the heaters and used on otherheaters that have not yet been heated. Lifting systems may be reattachedto the heaters when the formation is cooled to accommodate thermalcontraction of the heaters.

In some embodiments, the lifting systems may be controlled based on thehydraulic pressure of the lifters. Change in the tension of the pipe mayresult in a change in the hydraulic pressure. The control system maymaintain the hydraulic pressure substantially at a set point hydraulicpressure to provide accommodation of thermal expansion of the heater inthe formation.

In some embodiments, the circulation system uses a liquid to heat theformation. The use of liquid heat transfer fluid may allow for highoverall energy efficiency for the system as compared to electricalheating or gas heaters due to the high energy efficiency of heatsupplies used to heat the liquid heat transfer fluid. If furnaces areused to heat the liquid heat transfer fluid, the carbon dioxidefootprint of the process may be reduced as compared to electricallyheating or using gas burners positioned in wellbores due to theefficiencies of the furnaces. If nuclear power is used to heat theliquid heat transfer fluid, the carbon dioxide footprint of the processmay be significantly reduced or eliminated. The surface facilities forthe heating system may be formed from commonly available industrialequipment in simple layouts. The commonly available equipment in simplelayouts increases the overall reliability of the system.

The liquid heat transfer fluid may be a molten salt or other liquid thathas the potential to solidify if the temperature becomes too low. Asecondary heating system may be needed to ensure that heat transferfluid remains in liquid form and that the heat transfer fluid is at atemperature that allows the heat transfer fluid to flow through theheaters by the circulation system. The secondary heating system may notheat the heater and/or the heat transfer fluid to a high temperature,but only to a temperature sufficient to melt and ensure flowability ofthe heat transfer fluid. The secondary heating system may only be neededfor a short period of time during startup and or re-startup of the fluidcirculation system. In some embodiments, the secondary heating system isremovable from the heater. In some embodiments, the secondary heatingsystems are not made to last for the life of the heater.

In an embodiment, molten salt is used as the heat transfer fluid.Insulated return storage tanks receive return molten salt from theformation. Temperatures in the return storage tanks may be in thevicinity of about 350° C. Pumps may move the molten salt to furnaces.Each of the pumps may need to move from 4 kg/s to 30 kg/s of the moltensalt. Each furnace may provide heat to molten salt. The molten salt maypass from the piping to insulated feed storage tanks. Exit temperaturesof the molten salt from the furnaces may be about 550° C. The moltensalt may pass from the furnaces to insulated feed storage tanks. Eachfeed storage stank may supply molten salt to 50 or more piping systemsthat enter into the formation. The molten salt flows through theformation and to return storage tanks. The furnaces may haveefficiencies that are 90% or greater. Heat loss to the overburden may be8% or less.

In some embodiments, the heaters for the circulation systems includeinsulation along the lengths of the heaters, including portions of theheaters that will be used to heat the treatment area. The insulation mayfacilitate insertion of the heaters into the formation. The insulationadjacent to portions that are to be used to heat the treatment area maybe sufficient to provide insulation during preheating, but may decomposeat temperatures provided by the heat transfer fluid during steadyoperation of the circulation system. In some embodiments, the insulationlayer changes the emissivity of the heater so that radiative heattransfer from the heater is inhibited. After decomposition of theinsulation, the emissivity of the heater may promote radiative heattransformation to the treatment area. The insulation may reduce the timeneeded to raise the temperature of the heaters and/or the heat transferfluid in the heaters to temperatures sufficient to ensure melt andflowability. In some embodiments, the insulation adjacent to portions ofthe heaters that will heat the treatment area may include polymercoatings. Insulation of portions of the heaters adjacent to theoverburden is different than the insulation of the heaters adjacent tothe portions of the heaters that are to heat the treatment area. Theinsulation of the heaters adjacent to the overburden is able to survivefor the life of the heaters.

In some embodiments, degradable insulation material (for example, apolymer foam) may be introduced into the wellbore after or duringplacement of the heater. The degradable insulation may provideinsulation adjacent to the portions of the heaters that are to heat thetreatment area during preheating. The liquid heat transfer fluid used toheat the treatment area may raise the temperature sufficiently of theheater enough to degrade and eliminate the insulation layer.

In some embodiments, the secondary heating system may electrically heatthe heaters of the fluid circulation system. In some embodiments,electricity is applied directly to the heat transfer fluid conduit toresistively heat the heat transfer fluid conduit. Directly heating theheat transfer fluid conduit may require large current because of therelatively low resistance of the heat transfer fluid conduit. A returncurrent path may be needed.

In some embodiments, the heat transfer fluid conduit may includeferromagnetic material that allows the effective resistance of the heattransfer fluid conduit to be high due to the skin effect heating whentime varying current is applied to the heat transfer fluid conduit. Forexample, the heat transfer fluid conduit may be made of steel with 9% to13% by weight chromium, such as 410 stainless steel. A return currentpath may be needed.

Resistively heating the heater may require special considerations.Wellheads may need to include isolation flanges to ensure that thecurrent path travels down the subsurface conduits and not through thesurface pipe manifolds. Also, casings in the formation may need to bemade of a non-ferromagnetic material (for example, non-ferromagnetichigh manganese steel, fiberglass, or carbon fiber) to inhibit inductionthat heats the casing and surrounding formation. In some embodiments,the overburden section of the heater is a conduit-in-conduitconfiguration with a thermal barrier between the conduits. Theinsulation may limit the amount of heat transferred to the inner conduitand the molten salt. Making the outer conduit of a non-ferromagneticmaterial may allow for distribution of current between the inner conduitand the outer conduit that allows for adequate heating of the innerconduit and salt. Electrically conductive centralizers may be locatedbetween the casing and the heater.

FIG. 256 depicts a side view representation of an embodiment of a systemfor heating a portion of a formation using a circulated fluid systemand/or electrical heating. Wellheads 476 of heaters 802 may be coupledto heat transfer fluid circulation system 992 by piping. Wellheads 476may also be coupled to electrical power supply system 1006. In someembodiments, heat transfer fluid circulation system 992 is disconnectedfrom the heaters when electrical power is used to heat the formation. Insome embodiments, electrical power supply system 1006 is disconnectedfrom the heaters when heat transfer fluid circulation system 992 is usedto heat the formation.

Electrical power supply system 1006 may include transformer 580 andcables 686, 688. In certain embodiments, cables 686, 688 are capable ofcarrying high currents with low losses. For example, cables 686, 688 maybe thick copper or aluminum conductors. The cables may also have thickinsulation layers. In some embodiments, cable 686 and/or cable 688 maybe superconducting cables. The superconducting cables may be cooled byliquid nitrogen. Superconducting cables are available from Superpower,Inc. (Schenectady, N.Y., U.S.A.). Superconducting cables may minimizepower loss and/or reduce the size of the cables needed to coupletransformer 580 to the heaters. In some embodiments, cables 686, 688 maybe made of carbon nanotubes. Cables 686, 688 may be electrically coupledto heaters 802 to resistively heat the heaters.

FIG. 257 depicts a representation of heater 802 that may initially beresistively heated with the return current path provided by insulatedconductor 574. Electrical connection between a lead of transformer 580and heater 802 may be made near a first side of the heater. The otherlead of transformer 580 may be electrically coupled to insulatedconductor 574. Electrical connection 1870 between heater 802 andinsulated conductor 574 may be made on an opposite side of heater fromtransformer 580 to complete the electrical circuit. FIG. 258 depicts arepresentation of heater 802 that may initially be resistively heatedwith the return current path provided by two insulated conductors 574.Transformers 580 may be located on each side of heater 802. Leads fromtransformers 580 may be electrically coupled to heater 802. The otherleads for transformers 580 may be electrically coupled to insulatedconductors 574. Electrical connections between insulated conductors 574and heater 802 may be made near the center of the heater to complete theelectrical circuits. Insulated conductors 574 depicted in FIG. 257 andFIG. 258 may be good electrical conductors that provide little or noresistive heating. Insulated conductors 574 may be coupled to theoutside of heaters 802 as depicted, or the insulated conductors may bepositioned inside of the heaters.

In some embodiments, insulated conductors that resistively heat may beused to preheat and/or ensure heat transfer flow in heaters of a fluidcirculation system. FIG. 259 depicts a representation of insulatedconductors 574 used to resistively heat heaters 802 of a circulatedfluid heating system. Insulated conductors 574 may be coupled totransformer 580 in a three phase configuration. Lead in and lead outportions of insulated conductors may be good electrical conductors thatprovide little or no resistive heating. Portions of insulated conductors574 coupled to or positioned in heaters 802 may include material thatresistively heats to temperatures sufficient to heat the heat transferfluid in the heaters to a temperature sufficient to allow the heattransfer fluid to flow. The material may be ferromagnetic so theinsulated conductors are temperature limited heaters. The Curie pointtemperature limit or phase transition temperature limit of theferromagnetic material may allow the insulated conductors to reachtemperatures above but relatively close to the temperature needed toensure melt and flowability of heat transfer fluid in heaters 802.

FIG. 260 depicts insulated conductor 574 positioned in heater 802.Heater 802 is piping of the circulation system positioned in theformation. Electricity applied to insulated conductor 574 resistivelyheats the insulated conductor. The generated heat transfers to heater802 and heat transfer fluid in the heater. In some embodiments, theinsulated conductors may be strapped to the outside of the heatersinstead of being placed inside of the heaters. Insulated conductor 574may be a relatively thin mineral insulated conductor positioned in arelatively large diameter piping as shown and described with respect toFIG. 356. In some embodiments, insulated conductors positioned in theheaters may be placed inside of a protective sleeve. For example, theinsulated conductor with an outer diameter of about 0.6 inches may beplaced inside a 1 inch tube or pipe that is placed in the 5 inch heaterpipe.

In some embodiments, insulated conductors positioned inside or outsideheaters used with a circulated fluid heating system may provide currentthat is used to cause inductive heating. The current flowing through theinsulated conductors may be used to induce currents in the heater sothat the heater is resistively heated. In some embodiments, theinsulated conductors may be wrapped with a coil that is inductivelyheated. The coil may be made of a material that has a Curie temperaturelimit or phase transition temperature limit slightly higher than thetemperature needed to ensure melt and flowability of heat transfer fluidin the heaters.

In some embodiments, insulated conductors used as current paths or asheaters may be removable from heaters. After heat transfer fluidcirculation in a heater is initiated and stabilizes, the heat transferfluid will heat the adjacent formation to temperatures above thetemperature needed to ensure melt and flowability of the heat transferfluid. The heat of the formation and the heat of the heat transfer fluidmay be sufficient to ensure melt and flowability of the heat transferfluid should the circulation system temporarily be interrupted (forexample, for a day, a week, or a month). For heaters with the insulatedconductor positioned in the heater, the insulated conductors may bepulled out of the heater through seals in the wellhead that allow forelectrical connection to the insulated conductors. The insulatedconductors may be coiled and reused in heaters that have not beenpreheated. Should it be necessary, insulated conductor heaters may bereintroduced into the heaters.

In some embodiments of circulation systems that use molten salt or otherliquid as the heat transfer fluid, the heater may be a single conduit inthe formation. The conduit may be preheated to a temperature sufficientto ensure flowability of the heat transfer fluid. In some embodiments, asecondary heat transfer fluid is circulated through the conduit topreheat the conduit and/or the formation adjacent to the conduit. Afterthe temperature of the conduit and/or the formation adjacent to theconduit is sufficiently hot, the fluid may be flushed from the conduitand the heat transfer fluid may be circulated through the pipe. In someembodiments, aqueous solutions of the salt composition that is to beused as the heat transfer fluid are used to preheat the conduit. Thecomposition of the salt and/or the pressure of the system may beadjusted to inhibit boiling of the aqueous solution as the temperatureis increased. When the conduit is preheated to a temperature sufficientto ensure flowability of the molten salt, the remaining water may beremoved from the aqueous solution to leave only the molten salt. Thewater may be removed by evaporation while the salt solution is in astorage tank of the circulation system. After the heater is raised to atemperature sufficient to ensure continued flow of heat transfer fluidthrough the heater, a vacuum may be drawn on the passageway for thesecond heat transfer fluid to inhibit heat transfer from the firstpassageway to the second passageway. In some embodiments, the passagewayfor the second heat transfer fluid is filled with insulating materialand/or is otherwise blocked.

In some embodiments of circulation systems that use molten salt or otherliquid as the heat transfer fluid, the heater may have aconduit-in-conduit configuration. The liquid heat transfer fluid used toheat the formation may flow through a first passageway through theheater. A second heat transfer flow may flow through a second passagewaythrough the conduit-in-conduit heater for preheating and/or for flowassurance of the liquid heat transfer fluid. The passageways in theconduit of the conduit-in-conduit heater may include the inner conduitand the annular region between the inner conduit and the outer conduit.In some embodiments, one or more flow switchers are used to change theflow in the conduit-in-conduit heater from the inner conduit to theannular region and/or vice versa.

FIG. 261 depicts a cross-sectional view of an embodiment of heater 802for a heat transfer circulation heating system adjacent to treatmentarea 1028. Heater 802 may be positioned in wellbore 428. Heater 802 mayinclude outer conduit 1872 and inner conduit 1874. During normaloperation of heater 802, liquid heat transfer fluid may flow throughannular region 1876 between outer conduit 1872 and inner conduit 1874.During normal operation, fluid flow through inner conduit 1874 may notbe needed.

During preheating and/or for flow assurance, a secondary heat transferfluid may flow through inner conduit 1874. The secondary fluid may be,but is not limited to, air, carbon dioxide, exhaust gas, and/or anatural or synthetic oil (for example, DowTherm A, SylTHerm, orTherminol 59), room temperature molten salts (for example, NaCl₂—SrCl₂,VCl₄, SnCl₄, or TiCl₄), high pressure liquid water, steam, or roomtemperature molten metal alloys (for example, a K—Na eutectic or aGa—In—Sn eutectic). In some embodiments, outer conduit 1872 is heated bya secondary heat transfer fluid flowing through annular region 1876 (forexample, carbon dioxide or exhaust gas) before the heat transfer fluidthat is to be used to heat the formation is introduced into the annularregion. If exhaust gas or other high temperature fluid is used, anotherheat transfer fluid (for example, water or steam) may need to be passedthrough the heater to reduce the temperature below the upper workingtemperature limit of the liquid heat transfer fluid. The secondary heattransfer fluid may be displaced from the annular region when the liquidheat transfer fluid is introduced into the heater. The secondary heattransfer fluid in inner conduit 1874 may be the same fluid or adifferent fluid than the secondary fluid used to preheat outer conduit1872 during preheating. Using two different secondary heat transferfluids may allow for the identification of integrity problems in heater802. Any integrity problems may be identified and fixed before the useof the molten salt is initiated.

In some embodiments, the secondary heat transfer fluid that flowsthrough annular region 1876 during preheating is an aqueous mixture ofthe salt to be used during normal operation. The salt concentration maybe increased periodically to allow for increasing temperature whileremaining below the boiling temperature of the aqueous mixture. Theaqueous mixture may be used to raise the temperature of outer conduit1872 to a temperature sufficient to allow the molten salt to flow inannular region 1876. When the temperature is reached, the remainingwater in the aqueous mixture may be allowed to evaporate out of themixture to leave the molten salt. The molten salt may be used to heattreatment area 1028.

In some embodiments, inner conduit 1874 may be made of a relativeinexpensive material such as carbon steel. Inner conduit 1874 needs tosurvive through an initial early stage of the heat treatment process.Outer conduit 1872 may be made of material resistant to corrosion by themolten salt and formation fluid (for example, P91 steel).

For a given mass flow rate of liquid heat transfer fluid, heating atreatment area using liquid heat transfer fluid flowing in annularregion between outer conduit 1872 and inner conduit 1874 may havecertain advantages over flowing the liquid heat transfer fluid through asingle conduit. Flowing secondary heat transfer fluid through inner pipe1874 may pre-heat heater 802 and ensure flow when liquid heat transferfluid is first used and/or when flow needs to be restarted after a stopof circulation. The large outer surface area of outer conduit 1872provides a large surface area for heat transfer to the formation, whilestill allowing for reduced amount of liquid heat transfer fluid neededfor the circulation system because of the presence of inner conduit1874. The circulated liquid heat transfer fluid may deliver a betterpower injection rate distribution to the treatment area due to increasedvelocity of the liquid heat transfer fluid for the same mass flow rate.Reliability of the heater may be improved.

Having a conduit-in-conduit heater configuration allows flow switchersto be used that change the flow of heat transfer fluid in the heaterfrom flow through the annular region between the outer conduit and theinner conduit while adjacent to the treatment area to flow through theinner conduit while adjacent to the overburden. FIG. 262 depicts aschematic representation of conduit-in-conduit heaters 802 that are usedwith fluid circulation systems 992, 992′ to heat treatment area 1028.Heaters 802 include outer conduit 1872, inner conduit 1874, flowswitchers 1878. Fluid circulation systems 992, 992′ provide heatedliquid heat transfer fluid to wellheads 476. The direction of flow ofliquid heat transfer fluid is indicated by arrow 1880. Heat transferfluid from fluid circulation system 992 passes through wellhead 476 toinner conduit 1874. The heat transfer fluid passes through flow switcher1878 which changes the flow to the annular region between outer conduit1872 and inner conduit 1874. The heat transfer fluid flows throughtreatment area 1028. Heat from the heat transfer fluid is transferred totreatment area 1028. The heat transfer fluid passes through a secondflow switcher which changes the flow from the annular region to flowthrough inner conduit 1874. The heat transfer fluid flows through secondwellhead 476′ to fluid circulation system 992′. Heated heat transferfluid from fluid circulation systems 992′ passes through heater 802′back to fluid circulation system 992.

Using flow switchers 1878 to pass the fluid through the annular regionwhile the fluid is adjacent to treatment area 1028 promotes increasedheat transfer to the treatment area due in part to the large heattransfer area of outer conduit 1872. Using flow switchers 1878 to passthe fluid through the inner conduit when adjacent to overburden 482 mayreduce heat losses to the overburden. Additionally, heaters 802 may beinsulated adjacent to overburden 482 to reduce heat losses to theformation.

FIG. 263 depicts a cross-sectional view of an embodiment of aconduit-in-conduit heater 802 adjacent to overburden 482. Insulation1882 may be positioned between outer conduit 1872 and inner conduit1874. Liquid heat transfer fluid may flow through the center of innerconduit 1874. Insulation 1882 may be a highly porous insulation layerthat inhibits high temperature radiation (for example, temperaturesabove 500° C.) and allows flow of a secondary heat transfer fluid duringpreheating and/or flow assurance stages of heating. During normaloperating, flow of fluid through the annular region between outerconduit 1872 and inner conduit 1874 adjacent to overburden 482 may bestopped or inhibited.

Insulating sleeve 1836 may be positioned around outer conduit 1872.Insulating sleeves on each side of a u-shaped heater may be securelycoupled to outer conduit 1872 over a long length when the system is notheated so that the insulating sleeves on each side of the u-shapedwellbore are able to support the weight of the heater. Insulating sleeve1836 may include an outer member that is a structural member that allowsheater 802 to be lifted to accommodate thermal expansion of the heater.Casing 564 may surround insulating sleeve 1836. Insulating cement 1832may couple casing 564 to overburden 482. Insulating cement 1832 may be alow thermal conductivity cement that reduces conductive heat losses.Insulating cement 1832 may be a vermiculite/cement aggregate. Anon-reactive gas may be introduced into gap 1838 between insulatingsleeve 1836 and casing 564 to inhibit rising formation fluid and/or toprovide an insulating gas blanket.

FIG. 264 depicts a schematic of an embodiment of circulation system 992that supplies to liquid heat transfer fluid to conduit-in-conduitheaters positioned in the formation. Circulation system 992 may includeheat supply 994, compressor 1884, heat exchanger 1886, exhaust system1888, liquid storage tank 1890, pumps 1000, supply manifold 1892, returnmanifold 1894, and secondary heat transfer fluid circulation system1896.

Heat supply 994 may be a furnace. Fuel for heat supply 994 may besupplied through fuel line 1898. Control valve 1900 may regulate theamount of fuel supplied to heat supply 994 based on the temperature ofhot heat transfer fluid as measured by temperature monitor 1902.

Oxidant for heat supply 994 may be supplied through oxidant line 1904.Exhaust from heat supply 994 may pass through heat exchanger 1886 toexhaust system 1888. Oxidant from compressor 1884 may pass through heatexchanger 1886 to be heated by the exhaust from heat supply 994.

In some embodiments, valve 1906 may be opened during preheating and/orduring start-up of fluid circulation to the heaters to supply secondaryheat transfer fluid circulation system 1896 with a heating fluid. Insome embodiments, exhaust gas is circulated through the heaters bysecondary heat transfer fluid circulation system 1896. In someembodiments, the exhaust gas passes through one or more heat exchangersof secondary heat transfer fluid circulation system 1896 to heat fluidthat is circulated through the heaters.

During preheating, secondary heat transfer fluid circulation system 1896may supply secondary heat transfer fluid to the inner conduit of theheaters and/or to the annular region between the inner conduit and theouter conduit. Line 1912 may provide secondary heat transfer fluid tothe part of supply manifold 1892 that supplies fluid to the innerconduits of the heaters. Line 1914 may provide secondary heat transferfluid to the part of supply manifold 1892 that supplies fluid to theannular regions between the inner conduits and the outer conduits of theheaters. Line 1916 may return secondary heat transfer fluid from thepart of the return manifold 1894 that returns fluid from the innerconduits of the heaters. Line 1918 may return secondary heat transferfluid from the part of the return manifold 1894 that returns fluid fromthe annular regions of the heaters. Valves 1920 of secondary heattransfer fluid circulation system 1896 may allow or stop secondary heattransfer flow to or from supply manifold 1892 and/or return manifold1894. During preheating, all valves 1920 may be open. During the flowassurance stage of heating, valves 1920 for line 1912 and for line 1916may be closed, and valves 1920 for line 1914 and line 1918 may beclosed. Liquid heat transfer fluid from heat supply may be provided tothe part of supply manifold 1892 that supplies fluid to the innerconduits of the heaters during the flow assurance stage of heating.Liquid heat transfer fluid may return to supply tank from the portion ofreturn manifold 1894 that returns fluid from the inner conduits of theheaters. During normal operation, all valves 1920 may be closed.

Secondary heat transfer fluid circulation system 1896 may be a mobilesystem. Once normal flow of heat transfer fluid through the heaters isestablished, mobile secondary heat transfer fluid circulation systems1896 may be moved and attached to another circulation system that hasnot been initiated.

During normal operation, liquid storage tank 1890 may receive heattransfer fluid from return manifold 1894. Liquid storage tank 1890 maybe insulated and heat traced. Heat tracing may include steam circulationsystem 1908 that circulates steam through coils in liquid storage tank1890. Steam passed through the coils maintains heat transfer fluid inliquid storage tank 1890 at a desired temperature or in a desiredtemperature range.

Pumps 1000 may move liquid heat transfer fluid from liquid storage tank1890 to heat supply 994. In some embodiments, pumps 1000 are submersiblepumps that are positioned in liquid storage tank 1890. Having pumps 1000in storage tanks may keep the pumps at temperatures well within theoperating temperature limits of the pumps. Also, the heat transfer fluidmay function as a lubricant for the pumps. One or more redundant pumpsystems may be placed in liquid storage tank 1890. A redundant pumpsystem may be used if the primary pump system shuts down or needs to beserviced.

During start-up of heat supply 994, valves 1910 may be configured todirect liquid heat transfer fluid to liquid storage tank. Afterpreheating of a heater in the formation is completed, valves 1910 may bereconfigured to direct liquid heat transfer fluid to the part of supplymanifold 1892 that supplies the liquid heat transfer fluid to the innerconduit of the preheated heater. Return liquid heat transfer fluid fromthe inner conduit of a preheated return conduit may pass through thepart of return manifold 1894 that receives heat transfer fluid that haspassed through the formation and directs the heat transfer fluid toliquid storage tank 1890.

To begin using fluid circulation system 992, liquid storage tank 1890may be heated using steam circulation system 1908. The heat transferfluid may be added to liquid storage tank 1890. The heat transfer fluidmay be added as solid particles that melt in liquid storage tank 1890,or liquid heat transfer fluid may be added to the liquid storage tank.Heat supply 994 may be started, and pumps 1000 may be used to circulateheat transfer fluid from liquid storage tank 1890 to the heat supply andback. Secondary heat transfer fluid circulation system 1896 may be usedto heat heaters in the formation that are coupled to supply manifolds1892 and return manifolds 1894. Supply of secondary heat transfer fluidto the portion of supply manifold 1892 that feeds the inner conduits ofthe heaters may be stopped. The return of secondary heat transfer fluidfrom the portion of return manifold that receives heat transfer fluidfrom the inner conduits of the heaters may be stopped. Heat transferfluid from heat supply 994 may be directed to the inner conduit of theheaters.

The heat transfer fluid may flow through the inner conduits of theheaters to first flow switchers that change the flow of fluid from theinner conduits to the annular regions between the inner conduits and theouter conduits. The heat transfer fluid may pass through second flowswitchers that change the flow back to the inner conduits. Valvescoupled to the heaters may allow heat transfer fluid flow to theindividual heaters to be started sequentially instead of having thefluid circulation system supply heat transfer fluid to all of theheaters at once.

Return manifold receives heat transfer fluid that has passed throughheaters in the formation that are supplied from a second fluidcirculation system. Heat transfer fluid from return manifold 1894 may bedirected back into liquid storage tank 1890.

During initial heating, secondary heat transfer fluid circulation system1896 may continue to circulate secondary heat transfer fluid through theportion of the heater not receiving the heat transfer fluid suppliedfrom heat supply 994. In some embodiments, secondary heat transfer fluidcirculation system 1896 directs the secondary heat transfer fluid in thesame direction as the flow of heat transfer fluid supplied from heatsupply 994. In some embodiments, secondary heat transfer fluidcirculation system 1896 directs the secondary heat transfer fluid in theopposite direction to the flow of heat transfer fluid supplied from heatsupply 994. The secondary heat transfer fluid may ensure continued flowof the heat transfer fluid supplied from heat supply 994. Flow of thesecondary heat transfer fluid may be stopped when the secondary heattransfer fluid leaving the formation is hotter than the secondary heattransfer fluid supplied to the formation due to heat transfer with theheat transfer fluid supplied from heat supply 994. In some embodiments,flow of secondary heat transfer fluid may be stopped when otherconditions are met, such as the passage of a period of time.

FIG. 265 depicts a schematic representation of a system for providingand removing liquid heat transfer fluid to the treatment area of aformation using gravity and gas lifting as the driving forces for movingthe liquid heat transfer fluid. The liquid heat transfer fluid may be amolten metal or a molten salt. Vessel 1008 is elevated above heatexchanger 1010. Heat transfer fluid from vessel 1008 flows through heattransfer unit 1010 to the formation by gravity drainage. In anembodiment, heat exchanger 1010 is a tube and shell heat exchanger.Input stream 1012 is a hot fluid (for example, helium) from nuclearreactor 1014. Exit stream fluid 1016 may be sent as a coolant stream tonuclear reactor 1014. In some embodiments, the heat exchanger is afurnace, solar collector, chemical reactor, fuel cell, and/or other hightemperature source able to supply heat to the liquid heat transferfluid.

Hot heat transfer fluid from heat exchanger 1010 may pass to a manifoldthat provides heat transfer fluid to individual heater legs positionedin the treatment area of the formation. The heat transfer fluid may passto the heater legs by gravity drainage. The heat transfer fluid may passthrough overburden 482 to hydrocarbon containing layer 484 of thetreatment area. The piping adjacent to overburden 482 may be insulated.Heat transfer fluid flows downwards to sump 1018.

Gas lift piping may include gas supply line 1020 within conduit 1022.Gas supply line 1020 may enter sump 1018. When lift chamber 1024 in sump1018 fills to a selected level with heat transfer fluid, a gas liftcontrol system operates valves of the gas lift system so that the heattransfer fluid is lifted through the space between gas supply line 1020and conduit 1022 to separator 1026. Separator 1026 may receive heattransfer fluid and lifting gas from a piping manifold that transportsthe heat transfer fluid and lifting gas from the individual heater legsin the formation. Separator 1026 separates the lift gas from the heattransfer fluid. The heat transfer fluid is sent to vessel 1008.

Conduits 1022 from sumps 1018 to separator 1026 may include one or moreinsulated conductors or other types of heaters. The insulated conductorsor other types of heaters may be placed in conduits 1022 and/or bestrapped or otherwise coupled to the outside of the conduits. Theheaters may inhibit solidification of the heat transfer fluid inconduits 1022 during the gas lift from sump 1018.

In some embodiments, solar salt (i.e., a salt containing 60 wt % NaNO₃and 40 wt % KNO₃) may be used as the heat transfer fluid in a circulatedfluid system. Solar salt may have a melting point of about 230° C. andan upper temperature limit of about 565° C. In some embodiments, LiNO₃may be added to the NaNO₃ and KNO₃ mixture to produce tertiary saltmixtures with larger operating temperature ranges and lower meltingtemperatures, and only a slight decrease in the maximum workingtemperature as compared to solar salt. Table 2 shows the composition,melting point and upper temperature limit of several salt compositions.The lower melting temperature of the tertiary salt mixtures may decreasethe preheating requirements and allow the use of pressurized water as aheat transfer fluid for preheating the piping of the circulation system.The corrosion rates of the metal of the heaters due to the tertiary saltcompositions at 550° C. is comparable to the corrosion rate of the metalof the heaters due to solar salt at 565° C.

A portion of the heat input into a treatment area using circulated heattransfer fluid may recovered after the in suit heat treatment process iscompleted. Initially, the same heat transfer fluid used to heat thetreatment area may be circulated through the formation without the heatsource reheating the heat transfer fluid so that the heat transfer fluidabsorbs heat from the treatment area. The heat transfer fluid heated bythe treatment area may be circulated through an adjacent unheatedtreatment area to begin heating the unheated treatment area. In someembodiments, the heat transfer fluid heated by the treatment area passesthrough a heat exchanger to heat a second heat transfer fluid that isused to begin heating the unheated treatment area.

In some embodiments, a different heat transfer fluid than the heattransfer fluid used to heat the treatment area may be used to recoverheat from the formation. A different heat transfer fluid may be usedwhen the heat transfer fluid used to heat the treatment area has thepotential to solidify in the piping during recovery of heat from thetreatment area. The different heat transfer fluid may be a low meltingtemperature salt or salt mixture, steam, carbon dioxide, or a syntheticoil (for example, DowTherm or Therminol).

In some embodiments, initial heating of the formation may be performedusing circulated molten solar salt (NaNO₃—KNO₃) flowing through conduitsin the formation. Heating may be continued until fluid communicationbetween heater wells and producer wells is established and a relativelylarge amount of coke develops around the heater wells. Circulation maybe stopped and one or more of the conduits may be perforated. In anembodiment, the heater includes a perforated outer conduit and an innerliner that is chemically resistant to the heat transfer fluid. When heattransfer fluid is stopped, the liner may be withdrawn or chemicallydissolved to allow fluid flow from the heater into the formation. Inother embodiments, perforation guns may be used in the piping after flowof circulated heat transfer fluid is stopped. Nitrate salts or otheroxidizers may be introduced into the formation through the perforations.The nitrate salts or other oxidizers may oxidize the coke to finishheating the reservoir to desired temperatures. The concentration andamount of nitrate salts or other oxidizers introduced into the formationmay be controlled to control the heating of the formation. Oxidizing thecoke in the formation may heat the formation efficiently and reduce thetime for heating the formation to a desired temperature. Oxidationproduct gases may convectively transfer heat in the formation andprovide a gas drive that moves formation fluid towards the productionwells.

In some embodiments, nuclear energy is used to heat the heat transferfluid used in a circulation system to heat a portion of the formation.Heat supply 994 in FIG. 238 may be a pebble bed reactor or other type ofnuclear reactor, such as a light water reactor or a fissile metalhydride reactor. The use of nuclear energy provides a heat source withlittle or no carbon dioxide emissions. Also, in some embodiments, theuse of nuclear energy is more efficient because energy losses resultingfrom the conversion of heat to electricity and electricity to heat areavoided by directly utilizing the heat produced from the nuclearreactions without producing electricity.

In some embodiments, a nuclear reactor heats a heat transfer fluid suchas helium. For example, helium flows through a pebble bed reactor, andheat transfers to the helium. The helium may be used as the heattransfer fluid to heat the formation. In some embodiments, the nuclearreactor heats helium, and the helium is passed through a heat exchangerto provide heat to another heat transfer fluid used to heat theformation. The nuclear reactor may include a pressure vessel thatcontains encapsulated enriched uranium dioxide fuel. Helium may be usedas a heat transfer fluid to remove heat from the nuclear reactor. Heatmay be transferred in a heat exchanger from the helium to the heattransfer fluid used in the circulation system. The heat transfer fluidused in the circulation system may be carbon dioxide, a molten salt, orother fluids. Pebble bed reactor systems are available, for example,from PBMR Ltd (Centurion, South Africa).

FIG. 266 depicts a schematic diagram of a system that uses nuclearenergy to heat treatment area 1028. The system may include helium systemgas mover 1030, nuclear reactor 1032, heat exchanger unit 1034, and heattransfer fluid mover 1036. Helium system gas mover 1030 may blow, pump,or compress heated helium from nuclear reactor 1032 to heat exchangerunit 1034. Helium from heat exchanger unit 1034 may pass through heliumsystem gas mover 1030 to nuclear reactor 1032. Helium from nuclearreactor 1032 may be at a temperature between about 900° C. and about1000° C. Helium from helium gas mover 1030 may be at a temperaturebetween about 500° C. and about 600° C. Heat transfer fluid mover 1036may draw heat transfer fluid from heat exchanger unit 1034 throughtreatment area 1028. Heat transfer fluid may pass through heat transferfluid mover 1036 to heat exchanger unit 1034. The heat transfer fluidmay be carbon dioxide, a molten salt, and/or other fluids. The heattransfer fluid may be at a temperature between about 850° C. and about950° C. after exiting heat exchanger unit 1034.

In some embodiments, the system includes auxiliary power unit 1038. Insome embodiments, auxiliary power unit 1038 generates power by passingthe helium from heat exchanger unit 1034 through a generator to makeelectricity. The helium may be sent to one or more compressors and/orheat exchangers to adjust the pressure and temperature of the heliumbefore the helium is sent to nuclear reactor 1032. In some embodiments,auxiliary power unit 1038 generates power using a heat transfer fluid(for example, ammonia or aqua ammonia). Helium from heat exchanger unit1034 may be sent to additional heat exchanger units to transfer heat tothe heat transfer fluid. The heat transfer fluid may be taken through apower cycle (such as a Kalina cycle) to generate electricity. In anembodiment, nuclear reactor 1032 is a 400 MW reactor and auxiliary powerunit 1038 generates about 30 MW of electricity.

FIG. 267 depicts a schematic elevational view of an arrangement for anin situ heat treatment process. Wellbores (which may be U-shaped or inother shapes) may be formed in the formation to define treatment areas1028A, 1028B, 1028C, 1028D. Additional treatment areas could be formedto the sides of the shown treatment areas. Treatment areas 1028A, 1028B,1028C, 1028D may have widths of over 300 m, 500 m, 1000 m, or 1500 m.Well exits and entrances for the wellbores may be formed in wellopenings area 1040. Rail lines 1042 may be formed along sides oftreatment areas 1028. Warehouses, administration offices, and/or spentfuel storage facilities may be located near ends of rail lines 1042.Facilities 1044 may be formed at intervals along spurs of rail lines1042. One or more facilities 1044 may include a nuclear reactor,compressors, heat exchanger units, and/or other equipment needed forcirculating hot heat transfer fluid to the wellbores. Facilities 1044may also include surface facilities for treating formation fluidproduced from the formation. In some embodiments, heat transfer fluidproduced in facility 1044′ may be reheated by the reactor in facility1044″ after passing through treatment area 1028A. In some embodiments,each facility 1044 is used to provide hot treatment fluid to wells inone half of the treatment area 1028 adjacent to the facility. Facilities1044 may be moved by rail to another facility site after production froma treatment area is completed.

In some embodiments, nuclear energy is used to directly heat a portionof a subsurface formation. The portion of the subsurface formation maybe part of a hydrocarbon treatment area. As opposed to using a nuclearreactor facility to heat a heat transfer fluid, which is then providedto the subsurface formation to heat the subsurface formation, one ormore self-regulating nuclear heaters may be positioned underground todirectly heat the subsurface formation. The self-regulating nuclearreactor may be positioned in or proximate to one or more tunnels.

In some embodiments, treatment of the subsurface formation requiresheating the formation to a desired initial upper range (for example,between about 250° C. and 350° C.). After heating the subsurfaceformation to the desired temperature range, the temperature may bemaintained in the range for a desired time (for example, until apercentage of hydrocarbons have been pyrolyzed or an average temperaturein the formation reaches a selected value). As the formation temperaturerises, the heater temperature may be slowly lowered over a period oftime. Currently, certain nuclear reactors described (for example,nuclear pebble reactors), upon activation, reach a natural heat outputlimit of about 900° C., eventually decaying as the uranium-235 fuel isdepleted and resulting in lower temperatures at the heater produced overtime. The natural energy output curve of certain nuclear reactors (forexample, nuclear pebble reactors) may be used to provide a desiredheating versus time profile for certain subsurface formations.

In some embodiments, nuclear energy is provided by a self-regulatingnuclear reactor (for example, a pebble bed reactor or a fissile metalhydride reactor). The self-regulating nuclear reactor may not exceed acertain temperature based upon its design. The self-regulating nuclearreactor may be substantially compact relative to traditional nuclearreactors. The self-regulating nuclear reactor may be, for example,approximately 2 m, 3 m, or 5 m square or even less in size. Theself-regulating nuclear reactor may be modular.

FIG. 268 depicts a schematic representation of self-regulating nuclearreactor 1934. In some embodiments, the self-regulating nuclear reactorincludes fissile metal hydride 1936. The fissile metal hydride mayfunction as both fuel for the nuclear reaction as well as a moderatorfor the nuclear reaction. A core of the nuclear reactor may include ametal hydride material. The control of the nuclear reaction may functiondue to the temperature driven mobility of the hydrogen isotope containedin the hydride. If the temperature increases above a set point in core1938 of self-regulating nuclear reactor 1934, a hydrogen isotopedissociates from the hydride and escapes out of the core and the powerproduction decreases. If the core temperature decreases, the hydrogenisotope reassociates with the fissile metal hydride reversing theprocess. The fissile metal hydride may be in a powdered form, whichallows hydrogen to more easily permeate the fissile metal hydride.

Due to its basic design, the self-regulating nuclear reactor may includefew if any moving parts associated with the control of the nuclearreaction itself. The small size and simple construction of theself-regulating nuclear reactor may have distinct advantages, especiallyrelative to conventional commercial nuclear reactors used commonlythroughout the world today. Advantages may include relative ease ofmanufacture, transportability, security, safety, and financialfeasibility. The compact design of self-regulating nuclear reactors mayallow for the reactor to be constructed at one facility and transportedto a site of use, such as a hydrocarbon containing formation. Uponarrival and installation, the self-regulating nuclear reactor may beactivated.

Self-regulating nuclear reactors may produce thermal power on the orderof tens of megawatts per unit. Two or more self-regulating nuclearreactors may be used at the hydrocarbon containing formation.Self-regulating nuclear reactors may operate at a fuel temperatureranging between about 450° C. and about 900° C., between about 500° C.and about 800° C., or between about 550° C. and about 650° C. Theoperating temperature may be in the range between about 550° C. andabout 600° C. The operating temperature may be in the range betweenabout 500° C. and about 650° C.

Self-regulating nuclear reactors may include energy extraction system1940 in core 1938. Energy extraction system 1940 may function to extractenergy in the form of heat produced by the activated nuclear reactor.The energy extraction system may include a heat transfer fluid thatcirculates through piping 1940A and 1940B. At least a portion of thetubing may be positioned in the core of the nuclear reactor. A fluidcirculation system may function to continuously circulate heat transferfluid through the piping. Density and volume of piping positioned in thecore may be dependent on the enrichment of the fissile metal hydride.

In some embodiments, the energy extraction system includes alkali metal(for example, potassium) heat pipes. Heat pipes may further simplify theself-regulating nuclear reactor by eliminating the need for mechanicalpumps to convey a heat transfer fluid through the core. Anysimplification of the self-regulating nuclear reactor may decrease thechances of any malfunctions and increase the safety of the nuclearreactor. The energy extraction system may include a heat exchangercoupled to the heat pipes. Heat transfer fluids may convey thermalenergy from the heat exchanger.

The dimensions of the nuclear reactor may be determined by theenrichment of the fissile metal hydride. Nuclear reactors with a higherenrichment result in smaller relative reactors. Proper dimensions may beultimately determined by particular specifications of a hydrocarboncontaining formation and the formation's energy needs. In someembodiments, the fissile metal hydride is diluted with a fertilehydride. The fertile hydride may be formed from a different isotope ofthe fissile portion. The fissile metal hydride may include the fissilehydride U²³⁵ and the fertile hydride may include the isotope U²³⁸. Insome embodiments, the core of the nuclear reactor may include thenuclear fuel including about 5% of U²³⁵ and about 95% of U²³⁸.

Other combinations of fissile metal hydrides mixed with fertile ornon-fissile hydrides will also work. The fissile metal hydride mayinclude plutonium. Plutonium's low melting temperature (about 640° C.)makes the hydride particles less attractive as a reactor fuel to power asteam generator. The fissile metal hydride may include thorium hydride.Thorium permits higher temperature operation of the reactor because ofits high melting temperature (about 1755° C.). In some embodiments,different combinations of fissile metal hydride are used in order toachieve different energy output parameters.

In some embodiments, nuclear reactor 1934 may include one or morehydrogen storage containers 1942. A hydrogen storage container mayinclude one or more non-fissile hydrogen absorbing materials to absorbthe hydrogen expelled from the core. The non-fissile hydrogen absorbingmaterial may include a non-fissile isotope of the core hydride. Thenon-fissile hydrogen absorbing material may have a hydride dissociationpressure close to that of the fissile material.

Core 1938 and hydrogen storage containers 1942 may be separated byinsulation layer 1944. The insulation layer may function as a neutronreflector to reduce neutron leakage from the core. The insulation layermay function to reduce thermal feedback. The insulation layer mayfunction to protect the hydrogen storage containers from being heated bythe nuclear core (for example, with radiative heating or with convectiveheating from the gas within the chamber).

The effective steady-state temperature of the core may be controlled bythe ambient hydrogen gas pressure, which is controlled by thetemperature at which the non-fissile hydrogen absorbing material ismaintained. The temperature of the fissile metal hydride may beindependent of the amount of energy being extracted. The energy outputmay be dependent on the ability of the energy extraction system toextract the power from the nuclear reactor.

Hydrogen gas in the reactor core may be monitored for purity andperiodically repressurized to maintain the correct quantity and isotopiccontent. In some embodiments, the hydrogen gas is maintained via accessto the core of the nuclear reactor through one or more pipes (forexample, pipes 1946A and 1946B). The temperature of the self-regulatingnuclear reactor may be controlled by controlling a pressure of hydrogensupplied to the self-regulating nuclear reactor. The pressure may beregulated based upon the temperature of the heat transfer fluid at oneor more points (for example, at the point where the heat transfer fluidenters one or more wellbores). In some embodiments, the pressure may beregulated, and therefore the thermal energy produced by theself-regulating nuclear reactor, based on one or more conditionsassociated with the formation being treated. Formation conditions mayinclude, for example, temperature of a portion of the formation, type offormation (for example, coal or tar sands), and/or type of processingmethod being applied to the formation.

In some embodiments, the nuclear reaction occurring in theself-regulating nuclear reactor may be controlled by introducing aneutron-absorbing gas. The neutron-absorbing gas may, in sufficientquantities, quench the nuclear reaction in the self-regulating nuclearreactor (ultimately reducing the temperature of the reactor to ambienttemperature). The neutron-absorbing gas may include xenon¹³⁵.

In some embodiments, the nuclear reaction of an activatedself-regulating nuclear reactor is controlled using control rods.Control rods may be positioned at least partially in at least a portionof the nuclear core of the self-regulating nuclear reactor. Control rodsmay be formed from one or more neutron-absorbing material.Neutron-absorbing materials may include silver, indium, cadmium, boron,cobalt, hafnium, dysprosium, gadolinium, samarium, erbium, and/oreuropium.

Currently, self-regulating nuclear reactors described herein, uponactivation, reach a natural heat output limit of about 900° C.,eventually decaying as the fuel is depleted. The natural energy outputcurve of self-regulating nuclear reactors may be used to provide adesired heating versus time profile for certain subsurface formations.

In some embodiments, self-regulating nuclear reactors may have a naturalenergy output which decays at a rate of about 1/E (E is sometimesreferred to as Euler's number and is equivalent to about 2.71828).Typically, once a formation has been heated to a desired temperature,less heat is required and the amount of thermal energy put into theformation in order to heat the formation is reduced over time. In someembodiments, heat input to at least a portion of the formation over timeapproximately correlates to a rate of decay of the self-regulatingnuclear reactor. Due to the natural decay of self-regulating nuclearreactors, heating systems may be designed such that the heating systemstake advantage of the natural rate of decay of a nuclear reactor.Heaters are typically positioned in wellbores placed throughout theformation. Wellbores may include, for example, U-shaped and L-shapedwellbores or other shapes of wellbores. In some embodiments, spacingbetween wellbores is determined based on the decay rate of the energyoutput of self-regulating nuclear reactors.

The self-regulating nuclear reactor may initially provide, to at least aportion of the wellbores, an energy output of about 300 watts/foot; andthereafter decreasing over a predetermined time period to about 120watts/foot. The predetermined time period may be determined by thedesign of the self-regulating nuclear reactor itself (for example, fuelused in the nuclear core as well as the enrichment of the fuel). Thenatural decrease in energy output may match energy injection timedependence of the formation. Either variable (for example, power outputand/or power injection) may be adjusted so that the two variables atleast approximately correlate or match. The self-regulating nuclearreactor may be designed to decay over a period of 4-9 years, 5-7 years,or about 7 years. The decay period of the self-regulating nuclearreactor may correspond to an IUP (in situ upgrading process) and/or anICP (in situ conversion process) heating cycle.

FIG. 269 depicts curve 1948 of power (W/ft) (y-axis) versus time (yr)(x-axis) of the power injection requirements for a typical in situhydrocarbon remediation. FIG. 270 depicts power (W/ft) (y-axis) versustime (days) (x-axis) of in situ hydrocarbon remediation power injectionrequirements for different spacings between wellbores. Molten salt wascirculated through wellbores in a hydrocarbon containing formation andthe power requirements to heat the formation using molten salt wereassessed over time. The distance between the wellbores was varied todetermine the effect upon the power requirements. Curves 1960-1968depict the results in FIG. 270. Curve 1964 depicts power required versestime for the Grosmont formation in Alberta, Canada, with heaterwellbores laid out in a hexagonal pattern and with a spacing of about 12meters. Curve 1966 depicts power required verses time for heaterwellbores with a spacing of about 9.6 meters. Curve 1968 depicts powerrequired verses time for heater wellbores with a spacing of about 7.2meters. Curve 1962 depicts power required verses time for heaterwellbores with a spacing of about 13.2 meters. Curve 1960 depicts powerrequired verses time for heater wellbores with a spacing of about 14.4meters.

From the graph in FIG. 270, wellbore spacing represented by curve 1966may be the spacing which approximately correlates to the energy outputover time of certain nuclear reactors (for example, nuclear reactorshaving an energy output which decays at a rate of about 1/E). Curves1960-1964, in FIG. 270, depict the required energy output for heaterwellbores with spacing ranging from about 12 meters to about 14.4meters. Spacing between heater wellbores greater than about 12 metersmay require more energy input than certain nuclear reactors may be ableto provide. Spacing between heater wellbores less than about 8 meters(for example, as represented by curve 1968 in FIG. 270) may not makeefficient use of the energy input provided by certain nuclear reactors.

FIG. 271 depicts reservoir average temperature (° C.) (y-axis) versustime (days) (x-axis) of in situ hydrocarbon remediation for differentspacings between wellbores. Curves 1960-1968 depict the temperatureincrease in the formation over time based upon the power inputrequirements for the well spacing. A target temperature for in situremediation of hydrocarbon containing formations, in some embodiments,for example may be about 350° C. The target temperature for a formationmay vary depending on, at least, the type of formation and/or thedesired hydrocarbon products. The spacing between the wellbores forcurves 1960-1968 in FIG. 271 are the same for curves 1960-1968 in FIG.270. Curves 1960-1964, in FIG. 271, depict the increasing temperature inthe formation over time for heater wellbores with spacing ranging fromabout 12 meters to about 14.4 meters. Spacing between heater wellboresgreater than about 12 meters may heat the formation too slowly such thatmore energy may be required than certain nuclear reactors may be able toprovide (especially after about 5 years in the current example). Spacingbetween heater wellbores less than about 8 meters (for example, asrepresented by curve 1968 in FIG. 271) may heat the formation tooquickly for some in situ remediation situations. From the graph in FIG.271, wellbore spacing represented by curve 1966 may be the spacing thatachieves a typical target temperature of about 350° C. in a desirabletime frame (for example, about 5 years).

In some embodiments, spacing between heater wellbores depends on a rateof decay of one or more nuclear reactors used to provide power. In someembodiments, spacing between heater wellbores ranges between about 8meters and about 11 meters, between about 9 meters and about 10 meters,or between about 9.4 meters and about 9.8 meters.

In certain situations, it may be advantageous to continue a particularlevel of energy output of the self-regulating nuclear reactor for alonger period than the natural decay of the fuel material in the nuclearcore would normally allow. In some embodiments, in order to keep thelevel of output within a desired range, a second self-regulating nuclearreactor may be coupled to the formation being treated (for example,being heated). The second self-regulating nuclear reactor may, in someembodiments, have a decayed energy output. The energy output of thesecond reactor may have already decreased due to prior use. The energyoutput of the two self-regulating nuclear reactors may be substantiallyequivalent to the initial energy output of the first self-regulatingnuclear reactor and/or a desired energy output. Additionalself-regulating nuclear reactors may be coupled to the formation asneeded to achieve the desired energy output. Such a system mayadvantageously increase the effective useful lifetime of theself-regulating nuclear reactors.

The effective useful lifetime of self-regulating nuclear reactors may beextended by using the thermal energy produced by the nuclear reactor toproduce steam which, depending upon the formation and/or systems used,may require far less thermal energy than other uses outlined herein.Steam may be used for a number of purposes including, but not limitedto, producing electricity, producing hydrogen on site, convertinghydrocarbons, and/or upgrading hydrocarbons. Hydrocarbons may beconverted and/or mobilized in situ by injecting the produced steam inthe formation.

A product stream (for example, including methane, hydrocarbons, and/orheavy hydrocarbons) may be produced from a formation heated with heattransfer fluids heated by the nuclear reactor. Steam produced from heatgenerated by the nuclear reactor or a second nuclear reactor may be usedto reform at least a portion of the product stream. The product streammay be reformed to make at least some molecular hydrogen.

The molecular hydrogen may be used to upgrade at least a portion of theproduct stream. The molecular hydrogen may be injected in the formation.The product stream may be produced from a surface upgrading process. Theproduct stream may be produced from an in situ heat treatment process.The product stream may be produced from a subsurface steam heatingprocess.

At least a portion of the steam may be injected in a subsurface steamheating process. At least some of the steam may be used to reformmethane. At least some of the steam may be used for electricalgeneration. At least a portion of the hydrocarbons in the formation maybe mobilized.

In some embodiments, self-regulating nuclear reactors may be used toproduce electricity (for example, via steam driven turbines). Theelectricity may be used for any number of applications normallyassociated with electricity. Specifically, the electricity may be usedfor applications associated with IUP and ICP requiring energy.Electricity from self-regulating nuclear reactors may be used to provideenergy for downhole electric heaters.

Converting heat from self-regulating nuclear reactors into electricitymay not be the most efficient use of the thermal energy produced by thenuclear reactors. In some embodiments, thermal energy produced byself-regulating nuclear reactors is used to directly heat portions of aformation. In some embodiments, one or more self-regulating nuclearreactors are positioned underground in the formation such that thermalenergy produced directly heats at least a portion of the formation. Oneor more self-regulating nuclear reactors may be positioned undergroundin the formation below the overburden thus increasing the efficient useof the thermal energy produced by the self-regulating nuclear reactors.Self-regulating nuclear reactors positioned underground may be encasedin a material for further protection. For example, self-regulatingnuclear reactors positioned underground may be encased in a concretecontainer.

In some embodiments, thermal energy produced by self-regulating nuclearreactors may be extracted using heat transfer fluids. Thermal energyproduced by self-regulating nuclear reactors may be transferred to anddistributed through at least a portion of the formation using heattransfer fluids. Heat transfer fluids may circulate through the pipingof the energy extraction system of the self-regulating nuclear reactor.As heat transfer fluids circulate in and through the core of theself-regulating nuclear reactor, the heat produced from the nuclearreaction heats the heat transfer fluids.

In some embodiments, two or more heat transfer fluids may be employed totransfer thermal energy produced by self-regulating nuclear reactors. Afirst heat transfer fluid may circulate through the piping of the energyextraction system of the self-regulating nuclear reactor. The first heattransfer fluid may pass through a heat exchanger and used to heat asecond heat transfer fluid. The second heat transfer fluid may be usedfor treating hydrocarbon fluids in situ, powering electrolysis unit,and/or for other purposes. The first heat transfer fluid and the secondheat transfer fluid may be different materials. Using two heat transferfluids may reduce the risk of unnecessary exposure of systems andpersonnel to any radiation absorbed by the first heat transfer fluid.Heat transfer fluids that are resistant to absorbing nuclear radiationmay be used (for example, nitrite salts, nitrate salts).

In some embodiments, the energy extraction system includes alkali metal(for example, potassium) heat pipes. Heat pipes may further simplify theself-regulating nuclear reactor by eliminating the need for mechanicalpumps to convey a heat transfer fluid through the core. Anysimplification of the self-regulating nuclear reactor may decrease thechances of any malfunctions and increase the safety of the nuclearreactor. The energy extraction system may include a heat exchangercoupled to the heat pipes. Heat transfer fluids may convey thermalenergy from the heat exchanger.

Heat transfer fluids may include natural or synthetic oil, molten metal,molten salt, or other type of high temperature heat transfer fluid. Theheat transfer fluid may have a low viscosity and a high heat capacity atnormal operating conditions. When the heat transfer fluid is a moltensalt or other fluid that has the potential to solidify in the formation,piping of the system may be electrically coupled to an electricitysource to resistively heat the piping when needed and/or one or moreheaters may be positioned in or adjacent to the piping to maintain theheat transfer fluid in a liquid state. In some embodiments, an insulatedconductor heater is placed in the piping. The insulated conductor maymelt solids in the pipe.

In some embodiments, heat transfer fluids include molten salts. Moltensalts function well as heat transfer fluids due to their typicallystable nature as a solid and a liquid, their relatively high heatcapacity, and unlike water, their lack of expansion when they solidify.Molten salts have a fairly high melting point and typically a largerange over which the salt is liquid before it reaches a temperature highenough to decompose. Due to the wide variety of salts, a salt with adesirable temperature range may be found. If necessary, a mixture ofdifferent salts may be used in order to achieve a molten salt mixturewith the appropriate properties (for example, an appropriate temperaturerange).

In some embodiments, the molten salt includes a nitrite salt or acombination of nitrite salts. Examples of different nitrite salts mayinclude lithium, sodium, and/or potassium nitrite salts. The molten saltmay include about 15 to about 50 wt. % potassium nitrite salts and about50 to about 80 wt. % sodium nitrite salts. The molten salt may include anitrate salt or a combination of nitrate salts. Examples of differentnitrate salts may include lithium, sodium, and/or potassium nitratesalts. The molten salt may include about 15 to about 60 wt. % potassiumnitrate salts and about 40 to about 80 wt. % sodium nitrate salts. Themolten salt may include a mixture of nitrite and nitrate salts. In someembodiments, the molten salt may include HITEC and/or HITEC XL which areavailable from Coastal Chemical Co., L.L.C. located in Abbeville, La.,U.S.A. HITEC may include a eutectic mixture of sodium nitrite, sodiumnitrate, and potassium nitrate. HITEC may include a recommendedoperating temperature range of between about 149° C. and about 538° C.HITEC XL may include a eutectic mixture of calcium nitrate, sodiumnitrate, and potassium nitrate. In some embodiments, a manufacturingfacility may be used to convert nitrite salts to nitrate salts and/ornitrate salts to nitrite salts.

In some embodiments, the molten salt includes a customized mixture ofdifferent salts that achieve a desirable temperature range. A desirabletemperature range may be dependent upon the formation and/or materialbeing heated with the molten salt. TABLE 2 depicts ranges of differentmixtures of nitrate salts. TABLE 2 demonstrates how varying a ratio of amixture of different salts may affect the salt's usable temperaturerange as a heat transfer fluid. For example, a lithium doped nitratesalt mixture (for example, Li:Na:K:NO₃) has several advantages over thenon lithium doped nitrate salt mixture (for example, Na:K:NO₃). TheLi:Na:K:NO₃ salt mixture may offer a large operating temperature range.The Li:Na:K:NO₃ salt mixture may have a lower melting point, whichreduces the preheating requirements.

TABLE 2 Composition Melting Point Upper Limit NO₃ Salts (wt. %) (° C.)(° C.) Na:K 60:40 230 565 Li:Na:K 12:18:70 200 550 Li:Na:K 20:28:52 150550 Li:Na:K 27:33:40 160 550 Li:Na:K 30:18:52 120 550

In some embodiments, pressurized hot water is used to preheat the pipingin heater wellbores such that molten salts may be used. Preheatingpiping in heater wellbores (for example, to at least approximate themelting point of the molten salt to be used) may inhibit molten saltsfrom freezing and occluding the piping when the molten salt is firstcirculated through the piping. Piping in the heater wellbore may bepreheated using pressurized hot water (for example, water at about 120°C. pressurized to about 15 psi). The piping may be heated until at leasta majority of the piping reaches a temperature approximate to thecirculating hot water temperature. In some embodiments, the hot water isflushed from the piping with air after the piping has been heated to thedesired temperature. A preheated molten salt (for example, Li:Na:K:NO₃)may then be circulated through the piping in the heater wellbores toachieve the desired temperature.

In some embodiments, a salt (for example, Li:Na:K:NO₃) is dissolved inwater to form a salt solution before circulating the salt through pipingin heater wellbores. Dissolving the salt in water may reduce thefreezing point (for example, from about 120° C. to about 0° C.) Suchthat the salt may be safely circulated through the piping with littlefear of the salt freezing and obstructing the piping. The salt solution,in some embodiments, is preheated (for example, to about 90° C.) beforecirculating the solution through the piping in heater wellbores. Thesalt solution may be heated at an elevated pressure (for example,greater than about 15 psi) to above the water's boiling point. As thesalt solution is heated to about 120° C., the water from the solutionmay evaporate. The evaporating water may be allowed to vent from theheat transfer fluid circulation system. Eventually, only the anhydrousmolten salt remains to heat the formation.

In some embodiments, preheating of piping in heater wellbores isaccomplished by a heat trace (for example, an electric heat trace). Theheat trace may be accomplished by using a cable and/or running currentdirectly through the pipe. In some embodiments, a relatively thinconductive layer is used to provide the majority of the electricallyresistive heat output of the temperature limited heater at temperaturesup to a temperature at or near the Curie temperature and/or the phasetransformation temperature range of the ferromagnetic conductor. Such atemperature limited heater may be used as the heating member in aninsulated conductor heater. The heating member of the insulatedconductor heater may be located inside a sheath with an insulation layerbetween the sheath and the heating member.

FIG. 272 depicts a schematic representation of an embodiment of an insitu heat treatment system positioned in formation 524 with u-shapedwellbores 1950 using self-regulating nuclear reactors 1934.Self-regulating nuclear reactors 1934, depicted in FIG. 272, may produceabout 70 MWth. In some embodiments, spacing between wellbores 1950 isdetermined based on the decay rate of the energy output ofself-regulating nuclear reactors 1934.

U-shaped wellbores may run down through overburden 482 and intohydrocarbon containing layer 484. The piping in wellbores 1950 adjacentto overburden 482 may include insulated portion 1082. Insulated storagetanks 1952 may receive molten salt from the formation 524 through piping1954. Piping 1954 may transport molten salts with temperatures rangingfrom about 350° C. to about 500° C. Temperatures in the storage tanksmay be dependent on the type of molten salt used. Temperatures in thestorage tanks may be in the vicinity of about 350° C. Pumps may move themolten salt to self-regulating nuclear reactors 1934 through piping1956. Each of the pumps may need to move 6 kg/sec to 12 kg/sec of themolten salt. Each self-regulating nuclear reactor 1934 may provide heatto the molten salt. The molten salt may pass from piping 1958 towellbores 1950. The heated portion of wellbore 1950 which passes throughlayer 484 may extend, in some embodiments, from about 8,000 feet toabout 10,000 feet. Exit temperatures of the molten salt fromself-regulating nuclear reactors 1934 may be about 550° C. Eachself-regulating nuclear reactor 1934 may supply molten salt to about 20or more wellbores 1950 that enter into the formation. The molten saltflows through the formation and back to storage tanks 1952 throughpiping 1954.

In some embodiments, nuclear energy is used in a cogeneration process.In an embodiment for producing hydrocarbons from a hydrocarboncontaining formation (for example, a tar sands formation), producedhydrocarbons may include one or more portions with heavy hydrocarbons.Hydrocarbons may be produced from the formation using more than oneprocess. In certain embodiments, nuclear energy is used to assist inproducing at least some of the hydrocarbons. At least some of theproduced heavy hydrocarbons may be subjected to pyrolysis temperatures.Pyrolysis of the heavy hydrocarbons may be used to produce steam. Steammay be used for a number of purposes including, but not limited to,producing electricity, converting hydrocarbons, and/or upgradinghydrocarbons.

In some embodiments, a heat transfer fluid is heated using aself-regulating nuclear reactor. The heat transfer fluid may be heatedto temperatures that allow for steam production (for example, from about550° C. to about 600° C.). In some embodiments, in situ heat treatmentprocess gas and/or fuel passes to a reformation unit. In someembodiments, in situ heat treatment process gas is mixed with fuel andthen passed to the reformation unit. A portion of in situ heat treatmentprocess gas may enter a gas separation unit. The gas separation unit mayremove one or more components from the in situ heat treatment processgas to produce the fuel and one or more other streams (for example,carbon dioxide, hydrogen sulfide). The fuel may include, but is notlimited to, hydrogen, hydrocarbons having a carbon number of at most 5,or mixtures thereof.

The reformer unit may be a steam reformer. The reformer unit may combinesteam with a fuel (for example, methane) to produce hydrogen. Forexample, the reformation unit may include water gas shift catalysts. Thereformation unit may include one or more separation systems (forexample, membranes and/or a pressure swing adsorption system) capable ofseparating hydrogen from other components. Reformation of the fueland/or the in situ heat treatment process gas may produce a hydrogenstream and a carbon oxide stream. Reformation of the fuel and/or the insitu heat treatment process gas may be performed using techniques knownin the art for catalytic and/or thermal reformation of hydrocarbons toproduce hydrogen. In some embodiments, electrolysis is used to producehydrogen from the steam. A portion or all of the hydrogen stream may beused for other purposes such as, but not limited to, an energy sourceand/or a hydrogen source for in situ or ex situ hydrogenation ofhydrocarbons.

Self-regulating nuclear reactors may be used to produce hydrogen atfacilities located adjacent to hydrocarbon containing formations. Theability to produce hydrogen on site at hydrocarbon containing formationsis highly advantageous due to the plurality of ways in which hydrogen isused for converting and upgrading hydrocarbons on site at hydrocarboncontaining formations.

In some embodiments, the first heat transfer fluid is heated usingthermal energy stored in the formation. Thermal energy in the formationmay be the result of a number of different remediation methods.

Self-regulating nuclear reactors have been discussed for uses associatedwith in situ hydrocarbon remediation, and self-regulating nuclearreactors do have several advantages over many current constant outputnuclear reactors. However, there are several new nuclear reactors whosedesigns have received regulatory approval for construction. Nuclearenergy may be provided by a number of different types of availablenuclear reactors and nuclear reactors currently under development (forexample, generation IV reactors).

In some embodiments, nuclear reactors include very high temperaturereactors (VHTR). VHTRs may use, for example, helium as a coolant todrive a gas turbine for treating hydrocarbon fluids in situ, powering anelectrolysis unit, and/or for other purposes. VHTRs may produce heat upto about 950° C. or more. In some embodiments, nuclear reactors includea sodium-cooled fast reactor (SFR). SFRs may be designed on a smallerscale (for example, 50 MWe) and therefore may be more cost effective tomanufacture on site for treating hydrocarbon fluids in situ, poweringelectrolysis units, and/or for other purposes. SFRs may be of a modulardesign and potentially portable. SFRs may produce temperatures rangingbetween about 500° C. and about 600° C., between about 525° C. and about575° C., or between 540° C. and about 560° C.

In some embodiments, pebble bed reactors are employed to provide thermalenergy. Pebble bed reactors may produce up to 165 MWe. Pebble bedreactors may produce temperatures ranging between about 500° C. andabout 1100° C., between about 800° C. and about 1000° C., or betweenabout 900° C. and about 950° C. In some embodiments, nuclear reactorsinclude supercritical-water-cooled reactors (SCWR) based at least inpart on previous light water reactors (LWR) and supercriticalfossil-fired boilers. SCWRs may produce temperatures ranging betweenabout 400° C. and about 650° C., between about 450° C. and about 550°C., or between about 500° C. and about 550° C.

In some embodiments, nuclear reactors include lead-cooled fast reactors(LFR). LFRs may be manufactured in a range of sizes, from modularsystems to several hundred megawatt or more sized systems. LFRs mayproduce temperatures ranging between about 400° C. and about 900° C.,between about 500° C. and about 850° C., or between about 550° C. andabout 800° C.

In some embodiments, nuclear reactors include molten salt reactors(MSR). MSRs may include fissile, fertile, and fission isotopes dissolvedin a molten fluoride salt with a boiling point of about 1,400° C. Themolten fluoride salt may function as both the reactor fuel and thecoolant. MSRs may produce temperatures ranging between about 400° C. andabout 900° C., between about 500° C. and about 850° C., or between about600° C. and about 800° C.

In some embodiments, two or more heat transfer fluids (for example,molten salts) are employed to transfer thermal energy to and/or from ahydrocarbon containing formation. A first heat transfer fluid may beheated (for example, with a nuclear reactor). The first heat transferfluid may be circulated through a plurality of wellbores in at least aportion of the formation in order to heat the portion of the formation.The first heat transfer fluid may have a first temperature range inwhich the first heat transfer fluid is in a liquid form and stable. Thefirst heat transfer fluid may be circulated through the portion of theformation until the portion reaches a desired temperature range (forexample, a temperature towards an upper end of the first temperaturerange).

A second heat transfer fluid may be heated (for example, with a nuclearreactor). The first heat transfer fluid may have a second temperaturerange in which the second heat transfer fluid is in a liquid form andstable. An upper end of the second temperature range may be hotter andabove the first temperature range. A lower end of the second temperaturerange may overlap with the first temperatures range. The second heattransfer fluid may be circulated through the plurality of wellbores inthe portion of the formation in order to heat the portion of theformation to a higher temperature than is possible with the first heattransfer fluid.

The advantages of using two or more different heat transfer fluids mayinclude, for example, the ability to heat the portion of the formationto a much higher temperature than is normally possible while using othersupplementary heating methods as little as possible to increase overallefficiency (for example, electric heaters). Using two or more differentheat transfer fluids may be necessary if a heat transfer fluid with alarge enough temperature range capable of heating the portion of theformation to the desired temperature is not available.

In some embodiments, after the portion of the hydrocarbon containingformation has been heated to a desired temperature range, the first heattransfer fluid may be recirculated through the portion of the formation.The first heat transfer fluid may not be heated before recirculationthrough the formation (other than heating the heat transfer fluid to themelting point if necessary in the case of molten salts). The first heattransfer fluid may be heated using the thermal energy already stored inthe portion of the formation from prior attempts at hydrocarbonremediation. The first heat transfer fluid may then be transferred outof the formation such that the thermal energy recovered by the firstheat transfer fluid may be reused for some other process in the portionof the formation, in a second portion of the formation, and/or in anadditional formation.

In some in situ heat treatment embodiments, compressors providecompressed gases to the treatment area. For example, compressors may beused to provide oxidizing fluid 806 and/or fuel 810 to a plurality ofoxidizer assemblies like oxidizer assembly 612 depicted in FIG. 197.Each oxidizer assembly 612 may include a number of oxidizers 614.Oxidizers 614 may burn a mixture of oxidizing fluid 806 and fuel 810 toproduce heat that heats the treatment area in the formation. Also,compressors 1000 may be used to supply gas phase heat transfer fluid tothe formation as depicted in FIG. 238. In some embodiments, pumpsprovide liquid phase heat transfer fluid to the treatment area.

A significant cost of the in situ heat treatment process may beoperating the compressors and/or pumps over the life of the in situ heattreatment process if conventional electrical energy sources are used topower the compressors and/or pumps of the in situ heat treatmentprocess. In some embodiments, nuclear power may be used to generateelectricity that operates the compressors and/or pumps needed for the insitu heat treatment process. The nuclear power may be supplied by one ormore nuclear reactors. The nuclear reactors may be light water reactors,pebble bed reactors, and/or other types of nuclear reactors. The nuclearreactors may be located at or near to the in situ heat treatment processsite. Locating the nuclear reactors at or near to the in situ heattreatment process site may reduce equipment costs and electricaltransmission losses over long distances. The use of nuclear power mayreduce or eliminate the amount of carbon dioxide generation associatedwith operating the compressors and/or pumps over the life of the in situheat treatment process.

Excess electricity generated by the nuclear reactors may be used forother in situ heat treatment process needs. For example, excesselectricity may be used to cool fluid for forming a low temperaturebarrier (frozen barrier) around treatment areas, and/or for providingelectricity to treatment facilities located at or near the in situ heattreatment process site. In some embodiments, the electricity or excesselectricity produced by the nuclear reactors may be used to resistivelyheat the conduits used to circulate heat transfer fluid through thetreatment area.

In some embodiments, excess heat available from the nuclear reactors maybe used for other in situ processes. For example, excess heat may beused to heat water or make steam that is used in solution miningprocesses. In some embodiments, excess heat from the nuclear reactorsmay be used to heat fluids used in the treatment facilities located nearor at the in situ heat treatment site.

In some embodiments, geothermal energy may be used to heat or preheat atreatment area of an in situ heat treatment process or a treatment areato be solution mined. Geothermal energy may have little or no carbondioxide emissions. In some embodiments, geothermally heated fluid may beproduced from a layer or layers located below or near the treatmentarea. The geothermally heated fluid includes, but is not limited to,steam, water, and/or brine. One or more of the layers may begeothermally pressurized geysers. Geothermally heated fluid may bepumped from one or more of the layers. The layer or layers may be atleast 2 km, at least 4 km, at least 8 km or more below the surface. Thegeothermally heated fluid may be at a temperature of at least 100° C.,at least 200° C., or at least 300° C.

The geothermally heated fluid may be produced and circulated throughpiping in the treatment area to raise the temperature of the treatmentarea. In some embodiments, the geothermally heated fluid is introduceddirectly into the treatment area. In some embodiments, the geothermallyheated fluid is circulated through the treatment area or piping in thetreatment area without being produced to the surface and re-introducedinto the treatment area. In some embodiments, the geothermally heatedfluid may be produced from a location near the treatment area. Thegeothermally heated fluid may be transported to the treatment area. Oncetransported to the treatment area, the geothermally heated fluid iscirculated through piping in the treatment area and/or the geothermallyheated fluid is introduced directly into the treatment area.

In some embodiments, geothermally heated fluid produced from a layer orlayers is used to solution mine minerals from the formation. Thegeothermally heated fluid may be used to raise the temperature of theformation to a temperature below the dissociation temperature of theminerals, but to a temperature high enough to increase the amount ofmineral going into solution in a first fluid introduced into theformation. The geothermally heated fluid may be introduced directly intothe formation as all or a portion of the first fluid, and/or thegeothermally heated fluid may be circulated through piping in theformation.

In some embodiments, geothermally heated fluid produced from a layer orlayers may be used to heat the treatment area before using electricalheaters, gas burners, or other types of heat sources to heat thetreatment area to pyrolysis temperatures. The geothermally heated fluidmay not be at a temperature sufficient to raise the temperature of thetreatment area to pyrolysis temperatures. Using the geothermally heatedfluid to heat the treatment area before using electrical heaters orother heat sources to heat the treatment area to pyrolysis temperaturesmay reduce energy costs for the in situ heat treatment process.

In some embodiments, hot dry rock technology may be used to producesteam or other hot heat transfer fluid from a deep portion of theformation. Injection wells may be drilled to a depth where the formationis hot. The injection wells may be at least 2 km, at least 4 km, or atleast 8 km deep. Sections of the formation adjacent to the bottomportions of the injection wells may be hydraulically, or otherwisefractured, to provide large contact area with the formation and/or toprovide flow paths to heated fluid production wells. Water, steam and/orother heat transfer fluid (for example, a synthetic oil or a naturaloil) may be introduced into the formation through the injection wells.Heat transfers to the introduced fluid from the formation. Steam and/orhot heat transfer fluid may be produced from the heated fluid productionwells. In some embodiments, the steam and/or hot heat transfer fluid isdirected into the treatment area from the production wells without firstproducing the steam and/or hot heat transfer fluid to the surface. Thesteam and/or hot heat transfer fluid may be used to heat a portion of ahydrocarbon containing formation above the deep hot portion of theformation.

In some embodiments, steam produced from heated fluid production wellsmay be used as the steam for a drive process (for example, a steam floodprocess or a steam assisted gravity drainage process). In someembodiments, steam or other hot heat transfer fluid produced throughheated fluid production wells is passed through U-shaped wellbores orother types of wellbores to provide initial heating to the formation. Insome embodiments, cooled steam or water, or cooled heat transfer fluid,resulting from the use of the steam and/or heat transfer fluid from thehot portion of the formation may be collected and sent to the hotportion of the formation to be reheated.

In certain embodiments, a controlled or staged in situ heating andproduction process is used to in situ heat treat a hydrocarboncontaining formation (for example, an oil shale formation). The stagedin situ heating and production process may use less energy input toproduce hydrocarbons from the formation than a continuous or batch insitu heat treatment process. In some embodiments, the staged in situheating and production process is about 30% more efficient in treatingthe formation than the continuous or batch in situ heat treatmentprocess. The staged in situ heating and production process may alsoproduce less carbon dioxide emissions than a continuous or batch in situheat treatment process. In certain embodiments, the staged in situheating and production process is used to treat rich layers in the oilshale formation. Treating only the rich layers may be more economicalthan treating both rich layers and lean layers because heat may bewasted heating the lean layers.

FIG. 273 depicts a top view representation of an embodiment for thestaged in situ heating and producing process for treating the formation.In certain embodiments, heaters 438 are arranged in triangular patterns.In other embodiments, heaters 438 are arranged in any other regular orirregular patterns. The heater patterns may be divided into one or moresections 1046, 1048, 1050, 1052, and/or 1054. The number of heaters 438in each section may vary depending on, for example, properties of theformation or a desired heating rate for the formation. One or moreproduction wells 206 may be located in each section 1046, 1048, 1050,1052, and/or 1054. In certain embodiments, production wells 206 arelocated at or near the centers of the sections. In some embodiments,production wells 206 are in other portions of sections 1046, 1048, 1050,1052, and 1054. Production wells 206 may be located at other locationsin sections 1046, 1048, 1050, 1052, and/or 1054 depending on, forexample, a desired quality of products produced from the sections and/ora desired production rate from the formation.

In certain embodiments, heaters 438 in one of the sections are turned onwhile the heaters in other sections remain turned off. For example,heaters 438 in section 1046 may be turned on while the heaters in theother sections are left turned off. Heat from heaters 438 in section1046 may create permeability, mobilize fluids, and/or pyrolysis fluidsin section 1046. While heat is being provided by heaters 438 in section1046, production wells 206 in section 1048 may be opened to producefluids from the formation. Some heat from heaters 438 in section 1046may transfer to section 1048 and “pre-heat” section 1048. Thepre-heating of section 1048 may create permeability in section 1048,mobilize fluids in section 1048, and allow fluids to be produced fromthe section through production wells 206.

In certain embodiments, portions of section 1048 proximate productionwells 206, however, are not heated by conductive heating from heaters438 in section 1046. For example, the superposition of heat from heaters438 in section 1046 does not overlap the portion proximate productionwells 206 in section 1048. The portion proximate production wells 206 insection 1048 may be heated by fluids (such as hydrocarbons) flowing tothe production well (for example, by convective heat transfer from thefluids).

As fluids are produced from section 1048, the movement of fluids fromsection 1046 to section 1048 transfers heat between the sections. Themovement of the hot fluids through the formation increases heat transferwithin the formation. Allowing hot fluids to flow between the sectionsuses the energy of the hot fluids for heating of unheated sectionsrather than removing the heat from the formation by producing the hotfluids directly from section 1046. Thus, the movement of the hot fluidsallows for less energy input to get production from the formation thanis required if heat is provided from heaters 438 in both sections to getproduction from the sections.

In certain embodiments, the temperature of the portion proximateproduction well 206 in section 1048 is controlled so that thetemperature in the portion is at most a selected temperature. Forexample, the temperature in the portion proximate the production wellmay be controlled so that the temperature is at most about 100° C., atmost about 200° C., or at most about 250° C. In some embodiments, thetemperature of the portion proximate production well 206 in section 1048is controlled by controlling the production rate of fluids through theproduction well. In some embodiments, producing more fluids increasesheat transfer to the production well and the temperature in the portionproximate the production well.

In some embodiments, production through production wells 206 in section1048 is reduced or turned off after the portions proximate theproduction wells reach the selected temperature. Reducing or turning offproduction through the production wells at higher temperatures keepsheated fluids in the formation. Keeping the heated fluids in theformation keeps energy in the formation and reduces the energy inputneeded to heat the formation. The selected temperature at whichproduction is reduced or turned off may be, for example, about 100° C.,about 200° C., or about 250° C.

In some embodiments, section 1046 and/or section 1048 may be treatedprior to turning on heaters 438 to increase the permeability in thesections. For example, the sections may be dewatered to increase thepermeability in the sections. In some embodiments, steam injection orother fluid injection may be used to increase the permeability in thesections.

In certain embodiments, after a selected time, heaters 438 in section1048 are turned on. Turning on heaters 438 in section 1048 may provideadditional heat to sections 1046, 1048 and 1050 to increase thepermeability, mobility, and/or pyrolysis of fluids in these sections. Insome embodiments, as heaters 438 in section 1048 are turned on,production in section 1048 is reduced or turned off (shut down) andproduction wells 206 in section 1050 are opened to produce fluids fromthe formation. Thus, fluid flows in the formation towards productionwells 206 in section 1050, and section 1050 is heated by the flow of hotfluids as described above for section 1048. In some embodiments,production wells 206 in section 1048 may be left open after the heatersare turned on in the section, if desired. In some embodiments,production in section 1048 is reduced or turned off at the selectedtemperature, as described above.

The process of reducing or turning off heaters and shifting productionto adjacent sections may be repeated for subsequent sections in theformation. For example, after a selected time, heaters in section 1050may be turned on and fluids are produced from production wells 206 insection 1052 and so on through the formation.

In some embodiments, heat is provided by heaters 438 in alternatingsections (for example, sections 1046, 1050, and 1054) while fluids areproduced from the sections in between the heated sections (for example,sections 1048 and 1052). After a selected time, heaters 438 in theunheated sections (sections 1048 and 1052) are turned on and fluids areproduced from one or more of the sections as desired.

In certain embodiments, a smaller heater spacing is used in the stagedin situ heating and producing process than in the continuous or batch insitu heat treatment processes. For example, the continuous or batch insitu heat treatment process may use a heater spacing of about 12 m whilethe in situ staged heating and producing process uses a heater spacingof about 10 m. The staged in situ heating and producing process may usethe smaller heater spacing because the staged process allows forrelatively rapid heating of the formation and expansion of theformation.

In some embodiments, the sequence of heated sections begins with theoutermost sections and moves inwards. For example, for a selected time,heat may be provided by heaters 438 in sections 1046 and 1054 as fluidsare produced from sections 1048 and 1052. After the selected time,heaters 438 in sections 1048 and 1052 may be turned on and fluids areproduced from section 1050. After another selected amount of time,heaters 438 in section 1050 may be turned on, if needed.

In certain embodiments, sections 1046-1054 are substantially equal sizedsections. The size and/or location of sections 1046-1054 may vary basedon desired heating and/or production from the formation. For example,simulation of the staged in situ heating and production processtreatment of the formation may be used to determine the number ofheaters in each section, the optimum pattern of sections and/or thesequence for heater power up and production well startup for the stagedin situ heating and production process. The simulation may account forproperties such as, but not limited to, formation properties and desiredproperties and/or quality in the produced fluids. In some embodiments,heaters 438 at the edges of the treated portions of the formation (forexample, heaters 438 at the left edge of section 1046 or the right edgeof section 1054) may have tailored or adjusted heat outputs to producedesired heat treatment of the formation.

In some embodiments, the formation is sectioned into a checkerboardpattern for the staged in situ heating and production process. FIG. 274depicts a top view of rectangular checkerboard pattern 1056 for thestaged in situ heating and production process. In some embodiments,heaters in the “A” sections (sections 1046A, 1048A, 1050A, 1052A, and1054A) may be turned on and fluids are produced from the “B” sections(sections 1046B, 1048B, 1050B, 1052B, and 1054B). After the selectedtime, heaters in the “B” sections may be turned on. The size and/ornumber of “A” and “B” sections in rectangular checkerboard pattern 1056may be varied depending on factors such as, but not limited to, heaterspacing, desired heating rate of the formation, desired production rate,size of treatment area, subsurface geomechanical properties, subsurfacecomposition, and/or other formation properties.

In some embodiments, heaters in sections 1046A are turned on and fluidsare produced from sections 1046B and/or sections 1048B. After theselected time, heaters in sections 1048A may be turned on and fluids areproduced from sections 1048B and/or 1050B. After another selected time,heaters in sections 1050A may be turned on and fluids are produced fromsections 1050B and/or 1052B. After another selected time, heaters insections 1052A may be turned on and fluids are produced from sections1052B and/or 1054B. In some embodiments, heaters in a “B” section thathas been produced from may be turned on when heaters in the subsequent“A” section are turned on. For example, heaters in section 1046B may beturned on when the heaters in section 1048A are turned on. Otheralternating heater startup and production sequences may also becontemplated for the in situ staged heating and production processembodiment depicted in FIG. 274.

In some embodiments, the formation is divided into a circular, ring, orspiral pattern for the staged in situ heating and production process.FIG. 275 depicts a top view of the ring pattern embodiment for thestaged in situ heating and production process. Sections 1046, 1048,1050, 1052, and 1054 may be treated with heater startup and productionsequences similar to the sequences described above for the embodimentsdepicted in FIGS. 273 and 274. The heater startup and productionsequences for the embodiment depicted in FIG. 275 may start with section1046 (going inwards towards the center) or with section 1054 (goingoutwards from the center). Starting with section 1046 may allowexpansion of the formation as heating moves towards the center of thering pattern. Shearing of the formation may be minimized or inhibitedbecause the formation is allowed to expand into heated and/or pyrolyzedportions of the formation. In some embodiments, the center section(section 1054) is cooled after treatment.

FIG. 276 depicts a top view of a checkerboard ring pattern embodimentfor the staged in situ heating and production process. The embodimentdepicted in FIG. 276 divides the ring pattern embodiment depicted inFIG. 275 into a checkerboard pattern similar to the checkerboard patterndepicted in FIG. 274. Sections 1046A, 1048A, 1050A, 1052A, 1054A, 1046B,1048B, 1050B, 1052B, and 1054B, depicted in FIG. 276, may be treatedwith heater startup and production sequences similar to the sequencesdescribed above for the embodiment depicted in FIG. 274.

In some embodiments, fluids are injected to drive fluids betweensections of the formation. Injecting fluids such as steam or carbondioxide may increase the mobility of hydrocarbons and may increase theefficiency of the staged in situ heating and production process. In someembodiments, fluids are injected into the formation after the in situheat treatment process to recover heat from the formation. In someembodiments, the fluids injected into the formation for heat recoveryinclude some fluids produced from the formation (for example, carbondioxide, water, and/or hydrocarbons produced from the formation). Theembodiments depicted in FIGS. 273-276 may be used for in situ solutionmining of the formation. Hot water or another fluid may be used to getpermeability in the formation at low temperatures for solution mining.

In certain embodiments, several rectangular checkerboard patterns (forexample, rectangular checkerboard pattern 1056 depicted in FIG. 274) areused to treat a treatment area of the formation. FIG. 277 depicts a topview of a plurality of rectangular checkerboard patterns 1056(1-36) intreatment area 1028 for the staged in situ heating and productionprocess. Treatment area 1028 may be enclosed by barrier 1058. Each ofrectangular checkerboard patterns 1056(1-36) may individually be treatedaccording to embodiments described above for the rectangularcheckerboard patterns.

In certain embodiments, the startup of treatment of rectangularcheckerboard patterns 1056(1-36) proceeds in a sequential process. Thesequential process may include starting the treatment of each of therectangular checkerboard patterns one by one sequentially. For example,treatment of a second rectangular checkerboard pattern (for example, theonset of heating of the second rectangular checkerboard pattern) may bestarted after treatment of a first rectangular checkerboard pattern andso on. The startup of treatment of the second rectangular checkerboardpattern may be at any point in time after the treatment of the firstrectangular checkerboard pattern has begun. The time selected forstartup of treatment of the second rectangular checkerboard pattern maybe varied depending on factors such as, but not limited to, desiredheating rate of the formation, desired production rate, subsurfacegeomechanical properties, subsurface composition, and/or other formationproperties. In some embodiments, the startup of treatment of the secondrectangular checkerboard pattern begins after a selected amount offluids have been produced from the first rectangular checkerboardpattern area or after the production rate from the first rectangularcheckerboard pattern increases above a selected value or falls below aselected value.

In some embodiments, the startup sequence for rectangular checkerboardpatterns 1056(1-36) is arranged to minimize or inhibit expansionstresses in the formation. In an embodiment, the startup sequence of therectangular checkerboard patterns proceeds in an outward spiralsequence, as shown by the arrows in FIG. 277. The outward spiralsequence proceeds sequentially beginning with treatment of rectangularcheckerboard pattern 1056-1, followed by treatment of rectangularcheckerboard pattern 1056-2, rectangular checkerboard pattern 1056-3,rectangular checkerboard pattern 1056-4, and continuing the sequence upto rectangular checkerboard pattern 1056-36. Sequentially starting therectangular checkerboard patterns in the outwards spiral sequence mayminimize or inhibit expansion stresses in the formation.

Starting treatment in rectangular checkerboard patterns at or near thecenter of treatment area 1028 and moving outwards maximizes the startingdistance from barrier 1058. Barrier 1058 may be most likely to fail whenheat is provided at or near the barrier. Starting treatment/heating ator near the center of treatment area 1028 delays heating of rectangularcheckerboard patterns near barrier 1058 until later times of heating intreatment area 1028 or at or near the end of production from thetreatment area. Thus, if barrier 1058 does fail, the failure of thebarrier occurs after a significant portion of treatment area 1028 hasbeen treated.

Starting treatment in rectangular checkerboard patterns at or near thecenter of treatment area 1028 and moving outwards also creates open porespace in the inner portions of the outward moving startup pattern. Theopen pore space allows portions of the formation being started at latertimes to expand inwards into the open pore space and, for example,minimize shearing in the formation.

In some embodiments, support sections are left between one or morerectangular checkerboard patterns 1056(1-36). The support sections maybe unheated sections that provide support against geomechanicalshifting, shearing, and/or expansion stress in the formation. In someembodiments, some heat may be provided in the support sections. The heatprovided in the support sections may be less than heat provided insiderectangular checkerboard patterns 1056(1-36). In some embodiments, eachof the support sections may include alternating heated and unheatedsections. In some embodiments, fluids are produced from one or more ofthe unheated support sections.

In some embodiments, one or more of rectangular checkerboard patterns1056(1-36) have varying sizes. For example, the outer rectangularcheckerboard patterns (such as rectangular checkerboard patterns1056(21-26) and rectangular checkerboard patterns 1056(31-36)) may havesmaller areas and/or numbers of checkerboards. Reducing the area and/orthe number of checkerboards in the outer rectangular checkerboardpatterns may reduce expansion stresses and/or geomechanical shifting inthe outer portions of treatment area 1028. Reducing the expansionstresses and/or geomechanical shifting in the outer portions oftreatment area 1028 may minimize or inhibit expansion stress and/orshifting stress on barrier 1058.

In certain embodiments, heat sources (for example, heaters) have unevenor irregular spacing in a heater pattern. For example, the space betweenheat sources in the heater pattern varies or the heat sources are notevenly distributed in the heater pattern. In certain embodiments, thespace between heat sources in the heater pattern decreases as thedistance from the production well at the center of the patternincreases. Thus, the density of heat sources (number of heat sources persquare area) increases as the heat sources get more distant from theproduction well.

In some embodiments, heat sources are evenly spaced (equally spaced orevenly distributed) in the heater pattern but have varying heat outputssuch that the heat sources provide an uneven or varying heatdistribution in the heater pattern. Varying the heat output of the heatsources may be used to, for example, effectively mimic having heatsources with varying spacing in the heater pattern. For example, heatsources closer to the production well at the center of the heaterpattern may provide lower heat outputs than heat sources at furtherdistances from the production well. The heater outputs may be variedsuch that the heater outputs gradually increase as the heat sourcesincrease in distance from the production well.

In certain embodiments, the uneven or irregular spacing of heat sourcesis based on regular geometric patterns. For example, the irregularspacing of heat sources may be based on a hexagonal, triangular, square,octagonal, other geometric combinations, and/or combinations thereof. Insome embodiments, heat sources are placed at irregular intervals alongone or more of the geometric patterns to provide the irregular spacing.In some embodiments, the heat sources are placed in an irregulargeometric pattern. In some embodiments, the geometric pattern hasirregular spacing between rows in the pattern to provide the irregularspacing of heat sources.

FIG. 278 depicts an embodiment of irregular spaced heat sources 202 withthe heater density increasing as distance from production well 206increases. In certain embodiments, production well 206 is located at ornear the center of the pattern of heat sources 202. In certainembodiments, heat sources 202 are heaters (for example, electricheaters). FIG. 278 depicts an embodiment of irregular spaced heatsources in a hexagonal pattern. FIG. 279 depicts an embodiment of anirregular spaced triangular pattern. FIG. 280 depicts an embodiment ofirregular spaced square pattern. Heat sources may be placed at desiredlocations along the rows depicted in FIG. 279 and FIG. 280. It is to beunderstood that the heat sources may be placed in any regular orirregular geometric pattern in the formation. Heat sources may bearranged in any regular or irregular geometric pattern (for example,regular or irregular triangle, regular or irregular hexagonal, regularor irregular rectagonal, circular, oval, elliptical, or combinationsthereof) as long as the heat source density increases as distance fromthe production well increases. In some embodiments, the heat sources arespaced asymmetrically around the production well with the heat sourcedensity increasing as the distance from the production well increases.The irregular patterns of heat sources may be a pattern of vertical (orsubstantially vertical) heat sources in a formation or a pattern ofhorizontal (or substantially horizontal) heat sources in the formation.

As shown in FIG. 278, heat sources 202 are represented by solid squaresin rows A, B, C, and D. Rows A, B, C, and D may be triangular and/orhexagonal rows (or rows in other shapes) of heat sources that havedecreasing space between the rows as the rows move away from productionwell 206. Heat sources 202 may be distributed regularly or irregularlyin rows A, B, C, and D (for example, the heaters may have equal ornon-equal spacing in the rows). In certain embodiments, heat sources areplaced in the rows such that the density of heat sources increases asthe heat sources are further distanced away from production well 206.Thus, the heat output from the heat sources per volume of formationincreases with distance from the production well.

In certain embodiments, the irregular pattern of heat sources has thesame number of heat sources per production well as a regular pattern ofheat sources but with heat source spacing that decreases with increasingdistance from the production well. The decreasing heat source spacingincreases the heat input into the formation per volume of formation asthe distance from the production well increases. FIG. 281 depicts anembodiment of a regular pattern of equally spaced rows of heat sources.The embodiments depicted in FIGS. 278 and 281 each have a pattern ratioof 16 heat sources 202 to one production well 206 (for example, 12 (fromrows A, B, C)+1 (from the three heat sources at the vertices of row Dbecause each of these heat sources supplies heat to three patterns)+3(from the 6 heat sources located in row D between the vertices becauseeach of these heat sources supplies heat to two patterns)). Theheater/producer ratio for both embodiments is 16:1 and the total heatinput into the formation per volume of formation in the pattern issubstantially equal (assuming equal and constant heat source outputs).The spacing between heat sources in the embodiment depicted in FIG. 278,however, is different than the spacing between heat sources in theembodiment depicted in FIG. 281. Thus, the average heat input per volumeof formation increases with increasing distance from the production wellin the embodiment depicted in FIG. 278 while the average heat input pervolume of formation is substantially uniform throughout the patterndepicted in FIG. 281. In some embodiments, the equally spaced embodimentdepicted in FIG. 281 may provide increasing heat input per volume offormation with increasing distance from the production well by adjustingthe heat output of the heat sources to increase with increasing distancefrom the production well.

FIG. 282 depicts an embodiment of irregular spaced heat sources 202defining volumes with increasing heat input density around productionwell 206. FIG. 282 depicts the same heater pattern as FIG. 278 withshading defining areas representing volumes 1970, 1972, 1974, and 1976.Increases in the shading in FIG. 282 represent increases in the heatinput density into the formation (heat input per volume of formation).First volume 1970 substantially surrounds production well 206; secondvolume 1972 substantially surrounds first volume 1970; third volume 1974substantially surrounds second volume 1972; and fourth volume 1976substantially surrounds third volume 1974. In certain embodiments, firstvolume 1970 does not include production well 206. In some embodiments,first volume 1970 includes production well 206.

In certain embodiments, at least one heat source 202 is located in firstvolume 1970, in second volume 1972, in third volume 1974, and/or infourth volume 1976. In some embodiments, at least two heat sources 202are located in first volume 1970, in second volume 1972, in third volume1974, and/or in fourth volume 1976. In some embodiments, at least threeheat sources 202 are located in first volume 1970, in second volume1972, in third volume 1974, and/or in fourth volume 1976.

In certain embodiments, all heat sources 202 located in first volume1970 are closer to production well 206 than any of the heaters in secondvolume 1972. In some embodiments, all heat sources 202 located in secondvolume 1972 are closer to production well 206 than any of the heaters inthird volume 1974. In some embodiments, all heat sources 202 located inthird volume 1974 are closer to production well 206 than any of theheaters in fourth volume 1976.

In certain embodiments, the average distance from production well 206 ofheat sources 202 in first volume 1970 is less than the average distancefrom production well 206 of heat sources 202 in second volume 1972. Insome embodiments, the average distance from production well 206 of heatsources 202 in second volume 1972 is less than the average distance fromproduction well 206 of heat sources 202 in third volume 1974. In someembodiments, the average distance from production well 206 of heatsources 202 in third volume 1974 is less than the average distance fromproduction well 206 of heat sources 202 in fourth volume 1976.

In certain embodiments, first volume 1970 is approximately equal involume to second volume 1972, third volume 1974, and/or fourth volume1976. In some embodiments, second volume 1972 is approximately equal involume to third volume 1974 and/or fourth volume 1976. In someembodiments, third volume 1974 is approximately equal in volume tofourth volume 1976.

In certain embodiments, as shown in FIGS. 278 and 282, first volume1970, second volume 1972, third volume 1974, and fourth volume 1976 haveincreasing average radial distances from production well 206 with theaverage radial distance of the first volume being the smallest and theaverage radial distance of the fourth volume being the largest. Thus,first volume 1970 is closer to production well 206 than second volume1972; the second volume is closer to the production well than thirdvolume 1974; and the third volume is closer to the production well thanfourth volume 1976.

The differences in density of heat sources 202 in rows A, B, C, and Dand/or the differences in heat output of the heat sources may producetemperature gradients in the section of the formation heated by thepattern of heat sources shown in FIGS. 278 and 282. Heat input into theformation from heat sources 202 in row A may approximately define firstvolume 1970. Heat input into the formation from heat sources 202 in rowB may approximately define second volume 1972. Heat input into theformation from heat sources 202 in row C may approximately define thirdvolume 1974. Heat input into the formation from heat sources 202 in rowD may approximately define fourth volume 1976.

In certain embodiments, volumes 1970, 1972, 1974, and 1976 haveboundaries that are defined approximately by the differences in heatsource density between rows A, B, C, and D. The shapes of the boundariesof volumes 1970, 1972, 1974, and 1976 and or the size of the volumes maybe defined, for example, by the location of heat sources 202, theheating characteristics of the heat sources, and the thermal and/orgeomechanical properties of the formation. The shapes and/or sizes ofvolumes 1970, 1972, 1974, and 1976 may vary based on changes in theabove example properties and/or the point in time during heating of theformation. The boundaries of volumes 1970, 1972, 1974, and 1976, asshown in FIGS. 278 and 282, approximate measurable temperaturedifferences in the section because of the changes in heater density (orheat source output) at a selected point in time during heating of thesection.

In some embodiments, the number of heat sources 202 per volume offormation in a volume increases from first volume 1970 to fourth volume1976. Thus, the heat source density increases from first volume 1970 tofourth volume 1976. Because the heat source density increases from firstvolume 1970 to fourth volume 1976, the average heat output of heatsources in first volume 1970 is less than the average heat output ofheat sources in second volume 1972; the average heat output of heatsources in the second volume is less than the average heat output ofheat sources in third volume 1974; and the average heat output of heatsources in the third volume is less than the average heat output of heatsources in fourth volume 1976.

In addition, because of the increasing heater density (or heat output)as distance from production well 206 increases; the heat input to theformation per volume of formation in first volume 1970 is less than theheat input to the formation per volume of formation in second volume1972; the heat input to the formation per volume of formation in thesecond volume is less than the heat input to the formation per volume offormation in third volume 1974; and the heat input to the formation pervolume of formation in the third volume is less than the heat input tothe formation per volume of formation in fourth volume 1976. Thus, firstvolume 1970 is at a lower average temperature than second volume 1972;the second volume is at a lower average temperature than third volume1974; and the third volume is at a lower average temperature than fourthvolume 1976.

Regardless of any change in the shapes and/or sizes of volumes 1970,1972, 1974, and 1976, the spatial relation of the volumes remainsconstant during heating of the formation (the first volume surrounds theproduction well with the other volumes surrounding the first volume,respectively). Similarly, heat input into the formation may increaseconstantly from first volume 1970 to fourth volume 1976.

In certain embodiments, the formation has sufficient permeability toallow fluids (for example, mobilized fluids) to flow towards productionwell 206 from the outermost heat sources in the pattern (heat sources202 in row D). The flow of fluids from the higher heat density portionsof the formation towards the production well provides convective heattransfer in the formation. Fluids may be cooled as the fluids movetowards the production well by transferring heat to the formation.Convective heat transfer from fluid flow in the formation may transferheat through the formation faster than conductive heat transfer. In someembodiments, convective heat transfer may be increased by providingunobstructed or substantially unobstructed flow paths from the outermostheat sources to the production well. Increasing heat transfer in theformation may increase heating efficiency and/or recovery efficiency fortreating the formation. For example, fluids mobilized by heat at longerdistances from the production well may provide heat to the formation asthe mobilized fluids move towards the production well. Providing someheat to the formation from movement of mobilized fluids may be a moreefficient use of heat provided to the formation.

In certain embodiments, fluids produced through production well 206include a majority of liquid hydrocarbons that are hydrocarbonsoriginally in place in the section the pattern surrounding theproduction well. The liquid hydrocarbons may be hydrocarbons that areliquids at 25° C. and 1 atm.

As shown in FIG. 278, hexagonal rows A, B, C, and D have varying spacingbetween the rows with rows A, B, and C being shifted outwards fromproduction well 206 using an “offset factor”. An offset factor of zeroproduces rows substantially equally spaced from each other. FIG. 281depicts an embodiment with equally spaced rows of hexagon. The offsetfactor may be used in a series of related equations to determine thespacing between rows. For example, equations may be used for a heaterpattern with four hexagonal rows surrounding a production well.

As shown in FIG. 278, the largest hexagon is the outer constraint of thepattern of heat sources around the production well. The largest hexagonhas radii R₁ and R₂ with R₁ being the larger radius (the radius to avertex of the hexagon) and R₂ being the smaller radius (the radius tothe bisect of a side of a hexagon). In the embodiment with equallyspaced hexagons, shown in FIG. 281 yields:r ₁ +r ₂ +r ₃ +r ₄ =R ₁  (EQN. 7)where r₁ is the radius from the center to the vertex of the firsthexagon, r₂ is the radius from the vertex of the first hexagon to thevertex of the second hexagon, r₃ is the radius from the vertex of thesecond hexagon to the vertex of the third hexagon, and r₄ is the radiusfrom the vertex of the third hexagon to the vertex of the fourth hexagon(the largest hexagon).For the equally spaced hexagon case, the four radii are equal so that:r ₁ =r ₂ =r ₃ =r ₄ =R ₁/4.  (EQN. 8)

For the case of four hexagons spaced geometrically, shown in FIG. 278,the hexagons may have an offset factor, s. The spacing of the hexagonsmay be described by:r′ ₁+4s+r′ ₂+3s+r′ ₃+2s+r′ ₄ +s=R ₁.  (EQN. 9)

If r′₁ is assumed to be a constant (r′₁=r′₂=r′₃=r′₄=r′), then:4r′+10s=R ₁.  (EQN. 10)

Certain assumptions may be made on the offset factor, s, so that thedimensions (the distances from the production well) of the four hexagonsmay be described accordingly:r′+4s=distance to the vertex of the first hexagon from the productionwell;  (EQN. 11)2r′+7s=distance to the vertex of the second hexagon from the productionwell;  (EQN. 12)3r′+9s=distance to the vertex of the third hexagon from the productionwell;  (EQN. 13)and4r′+10s=distance to the vertex of the fourth hexagon from the productionwell.  (EQN. 14)

Thus, for an offset factor of zero, the spacing of the hexagons would beequal, as shown in FIG. 281. FIG. 278 depicts hexagons geometricallyspaced with an offset factor of about 8 for a nominal spacing of about40 feet (about 12 m) between equally spaced hexagons.

Decreasing the density of heat sources 202 closer to production well206, as shown in FIG. 278, provides less heating at or near theproduction well. Providing less heat at or near the production well mayreduce the enthalpy of fluids produced through the production well. Lessheating at or near the production well may provide lower temperatures inthe production well such that less energy is removed from the formationthrough produced fluids and more energy is kept in the formation to heatthe formation. Thus, waste energy from the formation may be decreased.Decreasing waste energy in the formation increases energy efficiency(energy into the formation versus energy out of the formation) intreating the formation.

In certain embodiments, the average temperature of produced fluids ismaintained below a selected temperature. For example, the averagetemperature of produced fluids when about 50% of the hydrocarbons inplace are pyrolyzed may be maintained below about 310° C., below about200° C., or below about 190° C. In some embodiments, the averagetemperature of produced fluids when about 50% of the hydrocarbons inplace are mobilized may be maintained below about 310° C., below about200° C., or below about 190° C. In some embodiments, the averagetemperature of produced fluids when about 50% of the hydrocarbons inplace are produced may be maintained below about 310° C., below about200° C., or below about 190° C.

In some embodiments, reducing temperatures at or near the productionwell reduces costs associated with production well completion and/orreduces the potential for failures of piping or other equipment in theproduction well. For example, treating a formation using the patterndepicted in FIG. 278 may decrease the heat requirement by about 17%versus treating the formation with a regular triangular pattern of heatsources. The reduced requirement for heat injection likely occursbecause of convective heat transfer by the high temperature fluids inthe formation from high heat density areas (outer portions of the heaterpattern) to portions of the formation around the production well.

Less heating at or near the production well, however, may decreaserecovery efficiency (amount of oil in place recovered) in the formation.The reduced recovery efficiency may be due to more hydrocarbons beingleft unmobilized or unpyrolyzed in the formation at the end ofproduction and/or higher concentrations of charring or coking fromhigher temperatures being generated by the higher heater density in theouter portions of the heater pattern. The reduced recovery efficiencymay offset some of the benefits from the reduced energy input into theformation. In some embodiments, further increasing the density of heatsources as the distance from the production well increases (for example,increasing the offset factor in FIG. 278) reduces the recoveryefficiency to an extent that overtakes any benefits gained from reducingenergy input into the formation.

Larger offset factors may result in shorter time to production ramp upbecause of accelerated heating from the higher density of heat sources.The larger offset factors, however, also produce lower peak oilproduction rates and reduced recovery efficiency. In addition, at largeroffset factors, more rock may need to be heated to compensate for reduceliquid recovery from the formation. Lowering the offset factor increasesoil production rates and recovery efficiency but reduces the heatefficiency in treating the formation. Thus, a desired offset factor (forexample, desired increasing heater density pattern) may be a balancebetween the above described results.

In certain embodiments, simulations, calculations, and/or otheroptimization methods are used to assess or determine a desired heaterdensity pattern (for example, offset factor) for treating the formation.The desired heater density pattern may be assessed based on factors suchas, but not limited to, current or future economic conditions,production needs, and properties of the formation. In some embodiments,the simulations or calculations are used to vary the offset factor andassess a desired (for example, optimum) ratio of energy output from theformation versus energy input into the formation.

Table 3 summarizes data from simulations on three different heaterpatterns for cumulative oil production (in bbl), gas production (inMMscf), heat injection efficiency (heat injection per barrel oilproduced (in MMBtu/bbl)), and cumulative heat injection (MMBtu) onpatterns of heaters. Row 1 shows data for a simulation of the equallyspaced heater pattern shown in FIG. 281. Row 2 shows data for asimulation of the irregular spaced heater pattern shown in FIG. 278. Thesimulations that resulted in the data shown in row 1 and row 2 wereconstrained to have the same constant average formation temperature. Row3 shows data for a simulation of the irregular spaced heater patternshown in FIG. 278 with the added feature of leaving the heaters closestto the production well (heaters in row A) on for a longer period oftime. The heaters were left on until the cumulative heat injection inthe simulation equaled the cumulative heat injection for the simulationof the equally spaced heater pattern (data shown in row 1).

TABLE 3 Oil Heat inj. Cum. Heat Row (bbl) Gas (MMscf) efficiency(MMBtu/bbl) (MMBtu) 1 91,610 2.99 × 10² 1.157 1.06 × 10⁵ 2 85,666 1.43 ×10² 1.044 8.94 × 10⁴ 3 97,378 3.04 × 10² 1.089 1.06 × 10⁵

As shown by the data in rows 1 and 2 of Table 3, increasing the heatinput density as the distance from the production well increases usingthe irregular heat source pattern increases the heat injectionefficiency into the formation and reduces the cumulative heat injectioninto the formation. Oil production, however, is reduced using theirregular heat source pattern. The data in row 3 shows that adjustinghow heat is injected in the irregular heat source pattern (for example,by keeping heaters closer to the production well on longer) may increaseoil production to a value even higher than the value for the regular(equally spaced) heat source pattern while getting a heat injectionefficiency that is better than the regular heat source pattern. Furtheradjustments of how heat is injected in the heat source pattern (forexample, turning off heaters in the outer parts of the pattern sooner)may further increase heat injection efficiency and/or increase oilproduction.

It is to be understood that the pattern of heat sources and rowsdepicted in FIG. 278 is merely representative of one possible embodimentfor a pattern of heat sources that increase in heater density withdistance from the production well. Many other geometric or non-geometricpatterns of heat sources may also be used to provide the same functionof increasing the heater density, as depicted in FIG. 278. Simulations,calculations, and/or other optimization methods may be used to assess ordetermine a desired heater density pattern for treating the formationwith any desired geometric or non-geometric pattern. For example,simulations, calculations, and/or other optimization methods may be usedto assess and optimize the amount of heat output per volume of formationfrom the heat sources (or the heat source density) at different radialdistances from the production well so that the ratio of energy outputfrom the formation versus energy input into the formation is optimized.

In some embodiments, heat sources 202 in rows A, B, C, and D, depictedin FIG. 278, are turned on and off simultaneously. The heat sources maybe turned on and allowed to heat the formation to a selected averagetemperature before being turned off. The selected temperature may be,for example, a hydrocarbon mobilization temperature, a hydrocarbonvisbreaking temperature, or a hydrocarbon pyrolysis temperature.Simulations and/or calculations may be used to assess the selectedaverage temperature for a selected heater density pattern.

In some embodiments, heat sources 202 nearest production well 206 (forexample, heat sources 202 in rows A and/or B) are left on for longertimes than heat sources further away from the production well (forexample, heat sources 202 in rows C and/or D). Leaving heat sourcesnearer the production well on for longer times may allow for morehydrocarbon production from the formation. Thus, fewer hydrocarbons mayremain in place after production is completed and higher recoveryefficiencies may be achieved using a selected heater density pattern.Simulations and/or calculations may be used to assess desired times forturning on and off heat sources such that the ratio of energy outputfrom the formation versus energy input into the formation is optimized.In some embodiments, it may be possible to increase the recoveryefficiency by tailoring the heat output to recovery efficienciesachieved with regular heating patterns (for example, no offset factor)

In some embodiments, heat sources that are turned on for shorter times(for example, heat sources 202 in row D) are designed for shorterlifetimes. For example, heat sources 202 in row D may be designed tolast at most about 3 years or at most about 5 years. Other heat sourcesin the formation may be designed to last at least about 5 years or atleast about 10 years. Shorter lifetime heat sources may use lessexpensive materials and/or be less expensive to manufacture or installthan longer lifetime heat sources. Thus, using the shorter lifetime heatsources may reduce costs associated with treating the formation.

In some embodiments, heat sources 202, depicted in FIG. 278, are turnedon in a sequence from outside in towards production well 206. Forexample, heat sources 202 in row D may be turned on first, followed byheat sources 202 in row C, then heat sources 202 in row B, and lastlyheat sources 202 in row A. Such a heater startup sequence may treat theformation in a staged heating method with one or more of the outsideheat sources being spaced so that heat from the heat sources does notsuperposition or conductively heat the production well and heat isprimarily transferred through convection of fluids to the productionwell. For example, heat sources 202 in rows A-D may be considered to bein a first section of the formation and production well 206 is in asecond section adjacent to the first section.

In some embodiments, the temperature at or near production well 206 iscontrolled so that the temperature is at most a selected temperature.For example, the temperature at or near the production well may becontrolled so that the temperature is at most about 100° C., at mostabout 150° C., at most about 200° C., or at most about 250° C. Incertain embodiments, the temperature at or near production well 206 iscontrolled by reducing or turning off the heat provided by heat sources202 nearest the production well (for example, the heat sources in rowA). In some embodiments, the temperature at or near production well 206is controlled by controlling the production rate of fluids through theproduction well.

In certain embodiments, the heater pattern depicted in FIG. 278 is abase unit of a pattern repeated through a large portion of the formationto define a larger treatment area. FIG. 283 depicts three base units inthe formation. Additional base units may be formed if desired. Thenumber and/or arrangement of base units in a pattern may depend on, forexample, the size and/or shape of the formation being treated. Incertain embodiments, production wells 206 are located at or near thecenter of the repeating base units in the pattern. Heater wells 202 andproduction wells 206 may be used to treat and produce hydrocarbons fromthe formation using the pattern depicted in FIG. 283.

In certain embodiments, a solvation fluid and/or pressurizing fluid areused to treat the hydrocarbon formation in addition to the in situ heattreatment process. In some embodiments, a solvation fluid and/orpressurizing fluid is used after the hydrocarbon formation has beentreated using a drive process.

In some embodiments, heaters are used to heat a first section theformation. For example, heaters may be used to heat a first section offormation to pyrolysis temperatures to produce formation fluids. In someembodiments, heaters are used to heat a first section of the formationto temperatures below pyrolysis temperatures to visbreak and/or mobilizefluids in the formation. In other embodiments, a first section of aformation is heated by heaters prior to, during, or after a driveprocess is used to produce formation fluids.

Residual heat from first section may transfer to portions of theformation above, below, and/or adjacent to the first section. Thetransferred residual heat, however, may not be sufficient to mobilizethe fluids in the other portions of the formation towards productionwells so that recovery of the fluids from the colder sections fluids maybe difficult. Addition of a fluid (for example, a solvation fluid and/ora pressurizing fluid) may solubilize and/or drive the hydrocarbons inthe sections of the formation heated by residual heat towards productionwells. Addition of a solvating and/or pressurizing fluid to portions ofthe formation heated by residual heat may facilitate recovery ofhydrocarbons without requiring heaters to heat the additional sections.Addition of the fluid may allow for the recovery of hydrocarbons inpreviously produced sections and/or for the recovery of viscoushydrocarbons in colder sections of the formation.

In some embodiments, the formation is treated using the in situ heattreatment process for a significant time after the formation has beentreated with a drive process. For example, the in situ heat treatmentprocess is used 1 year, 2 years, 3 years, or longer after a formationhas been treated using drive processes. After heating the formation fora significant amount of time using heaters and/or injected fluid (forexample, steam), a solvation fluid may be added to the heated sectionand/or portions above and/or below the heated section. The in situ heattreatment process followed by addition of a solvation fluid and/or apressurizing fluid may be used on formations that have been left dormantafter the drive process treatment because further hydrocarbon productionusing the drive process is not possible and/or not economicallyfeasible. In some embodiments, the solvation fluid and/or thepressurizing fluid is used to increase the amount of heat provided tothe formation. In some embodiments, an in situ heat treatment processmay be used following addition of the solvation fluid and/orpressurizing fluid to increase the recovery of hydrocarbons from theformation.

In some embodiments, the solvation fluid forms an in situ solvationfluid mixture. Using the in situ solvation fluid may upgrade thehydrocarbons in the formation. The in situ solvation fluid may enhancesolubilization of hydrocarbons and/or and facilitate moving thehydrocarbons from one portion of the formation to another portion of theformation.

FIGS. 284 and 285 depict side view representations of embodiments forproducing a fluid mixture from the hydrocarbon containing formation. InFIGS. 284 and 285, heaters 438 have substantially horizontal heatingsections below overburden 482 in hydrocarbon layer 484 (as shown, theheaters have heating sections that go into and out of the page). Heaters438 provide heat to first section 1060 of hydrocarbon layer 484.Patterns of heaters, such as triangles, squares, rectangles, hexagons,and/or octagons may be used within first section 1060. First section1060 may be heated at least to temperatures sufficient to mobilize somehydrocarbons within the first section. A temperature of the heated firstsection 1060 may range from about 200° C. to about 240° C. In someembodiments, temperature within first section 1060 may be increased to apyrolyzation temperature (for example between 250° C. and 400° C.).

In certain embodiments, the bottommost heaters are located between about2 m and about 10 m from the bottom of hydrocarbon layer 484, betweenabout 4 m and about 8 m from the bottom of the hydrocarbon layer, orbetween about 5 m and about 7 m from the bottom of the hydrocarbonlayer. In certain embodiments, production wells 206A are located at adistance from the bottommost heaters 438 that allows heat from theheaters to superimpose over the production wells, but at a distance fromthe heaters that inhibits coking at the production wells. Productionwells 206A may be located a distance from the nearest heater (forexample, the bottommost heater) of at most ¾ of the spacing betweenheaters in the pattern of heaters (for example, the triangular patternof heaters depicted in FIGS. 284 and 285). In some embodiments,production wells 206A are located a distance from the nearest heater ofat most ⅔, at most ½, or at most ⅓ of the spacing between heaters in thepattern of heaters. In certain embodiments, production wells 206A arelocated between about 2 m and about 10 m from the bottommost heaters,between about 4 m and about 8 m from the bottommost heaters, or betweenabout 5 m and about 7 m from the bottommost heaters. Production wells206A may be located between about 0.5 m and about 8 m from the bottom ofhydrocarbon layer 484, between about 1 m and about 5 m from the bottomof the hydrocarbon layer, or between about 2 m and about 4 m from thebottom of the hydrocarbon layer.

In some embodiments, formation fluid is produced from first section1060. The formation fluid may be produced through production wells 206A.In some embodiments, the formation fluids drain by gravity to a bottomportion of the layer. The drained fluids may be produced from productionwells 206A positioned at the bottom portion of the layer. Production ofthe formation fluids may continue until a majority of condensablehydrocarbons in the formation fluid are produced. After the majority ofthe condensable hydrocarbons have been produced, first section 1060 heatfrom heaters 438 may be reduced and/or discontinued to allow a reductionin temperature in the first section. In some embodiments, after themajority of the condensable hydrocarbons have been produced, a pressureof first section 1060 may be reduced to a selected pressure after thefirst section reaches the selected temperature. Selected pressures mayrange between about 100 kPa and about 1000 kPa, between 200 kPa and 800kPa, or below a fracture pressure of the formation.

In some embodiments, the formation fluid produced from production wells206 includes at least some pyrolyzed hydrocarbons. Some hydrocarbons maybe pyrolyzed in portions of first section 1060 that are at highertemperatures than a remainder of the first section. For example,portions of formation adjacent to heaters 438 may be at somewhat highertemperatures than the remainder of first section 1060. The highertemperature of the formation adjacent to heaters 438 may be sufficientto cause pyrolysis of hydrocarbons. Some of the pyrolysis product may beproduced through production wells 206.

One or more sections may be above and/or below first section 1060 (forexample, second section 1062 and/or third section 1064 depicted in FIG.284). FIG. 285 depicts second section 1062 and/or third section 1064adjacent to first section 1060. In some embodiments, second sectionsecond section 1062 and third section 1064 are outside a perimeterdefined by the outermost heaters. Some residual heat from first section1060 may transfer to second section 1062 and third section 1064. In someembodiments, sufficient residual heat is transferred to heat formationfluids to a temperature that allows the fluids to move in second section1062 and/or third section 1064 towards productions wells 206.Utilization of residual heat from first section 1060 to heathydrocarbons in second section 1062 and/or third section 1064 may allowhydrocarbons to be produced from the second section and/or third sectionwithout direct heating of these sections. A minimal amount of residualheat to second section 1062 and/or third section 1064 may besuperposition heat from heaters 438. Areas of second section 1062 and/orthird section 1064 that are at a distance greater than the spacingbetween heaters 438 may be heated by residual heat from first section1060. Second section 1062 and/or third section 1064 may be heated byconductive and/or convective heat from first section 1060. A temperatureof the sections heated by residual heat may range from 100° C. to 250°C., from 150° C. to 225° C., or from 175° C. to 200° C. depending on theproximity of heaters 438 to second section 1062 and/or third section1064.

In some embodiments, a solvation fluid is provided to first section 1060through injection wells 788A to solvate hydrocarbons within the firstsection. In some embodiments, solvation fluid is added to first section1060 after a majority of the condensable hydrocarbons have been producedand the first section has cooled. The solvation fluid may solvate and/ordilute the hydrocarbons in first section 1060 to form a mixture ofcondensable hydrocarbons and solvation fluids. Formation of the mixturemay allow for production of hydrocarbons remaining in the first section.Solubilization of hydrocarbons in first section 1060 may allow thehydrocarbons to be produced from the first section after heat has beenremoved from the section. The mixture may be produced through productionwells 206A.

In some embodiments, a solvation fluid is provided to second section1062 and/or third section 1064 through injection wells 788B and/or 788Cto increase mobilization of hydrocarbons within the second sectionand/or the third section. The solvation fluid may increase a flow ofmobilized hydrocarbons into first section 1060. For example, a pressuregradient may be produced between second section 1062 and/or thirdsection 1064 and first section 1060 such that the flow of fluids fromthe second section and/or the third section to the first section isincreased. The solvation fluid may solubilize a portion of thehydrocarbons in second section 1062 and/or third section 1064 to form amixture. Solubilization of hydrocarbons in second section 1062 and/orthird section 1064 may allow the hydrocarbons to be produced from thesecond section and/or third section without direct heating of thesections. In some embodiments, second section 1062 and/or third section1064 have been heated from residual heat transferred from first section1060 prior to addition of the solvation fluid. In some embodiments, thesolvation fluid is added after second section 1062 and/or third section1064 have been heated to a desired temperature by heat from firstsection 1060. In some embodiments, heat from first section 1060 and/orheat from the solvation fluid heats section 1062 and/or third section1064 to temperatures sufficient to mobilize heavy hydrocarbons in thesections. In some embodiments, section 1062 and/or third section 1064are heated to temperatures ranging from 50° C. to 250° C. In someembodiments, temperatures in section 1062 and/or third section 1064 aresufficient to mobilize heavy hydrocarbons, thus the solvation fluid maymobilize the heavy hydrocarbons by displacing the heavy hydrocarbonswith minimal mixing.

In some embodiments, water and/or emulsified water may be used as asolvation fluid. Water may be injected into a portion of first section1060, second section 1062 and/or third section 1064 through injectionwells 788. Addition of water to at least a selected section of firstsection 1060, second section 1062 and/or third section 1064 may watersaturate a portion of the sections. The water saturated portions of theselected section may be pressurized by known methods and awater/hydrocarbon mixture may be collected using one or more productionwells 206.

In some embodiments, a hydrocarbon formation and/or sections of ahydrocarbon formation may be heated to a selected temperature using aplurality of heaters. Heat from the heaters may transfer from theheaters so that a section of the formation reaches a selectedtemperature. Treating the hydrocarbon formation with hot water or “nearcritical” water may extract and/or solvate hydrocarbons from theformation that have been difficult to produce using other solventprocesses and/or heat treatment processes. Not to be bound by theory,near critical water may solubilize organic material (for example,hydrocarbons) normally not soluble in water. The solubilized and/ormobilized hydrocarbons may be produced from the formation. In otherembodiments, the formation is treated with critical or near criticalcarbon dioxide instead of hot water or near critical water.

In some embodiments, the hydrocarbon formation or one or more section ofthe formation may be heated (for example, using heaters) to atemperature ranging from about 100° C. to about 240° C., from about 150°C. to about 230° C., or from about 200° C. to about 220° C. In someembodiments, the hydrocarbon formation is an oil shale formation. Insome embodiments, temperature within the section may be increased to apyrolyzation temperature (for example, between about 250° C. and about400° C.). During heating, hydrocarbons may be transformed into lighterhydrocarbons, water and gas. The hydrocarbons may include bitumen. Insome embodiments, kerogen in an oil formation may be transformed intohydrocarbons, water and gas. During the transformation at least some thekerogen may be transformed into bitumen. In some embodiments, bitumenmay flow into heater and/or production wells and solidify.Solidification of the bitumen may decrease connectivity in the heaterand/or decrease production of hydrocarbons. In some embodiments,production of the bitumen is difficult due to the flow properties ofbitumen.

In some embodiments, after heating the section to the desiredtemperature, the bitumen may be treated with hot water and/or a hotsolution of water and solvent (for example, a solution of water andaromatics such as phenol and cresol). Hot water (for example, water attemperatures above 275° C., above 300° C. or above 350° C.) and/or a hotsolution (for example, a hot solution of water and one or more aromaticcompounds such as phenol and/or cresol compounds) may be injected in theformation (for example, an oil shale formation) or sections of theformation through heater, production, and/or injection wells. Pressureand temperature in the formation and/or the wells may be controlled tomaintain the most of the water in a liquid phase. For example, the watertemperature may range from about 250° C. to about 300° C. at pressuresranging from 5,000 kPa to 15,000 kPa or from 6,000 kPa to 10,000 kPa.Water at these temperatures at pressure may have a dielectric constantof about 20 and a density of about 0.7 grams per cubic centimeter. Insome embodiments, keeping most of the hot water in a liquid phase mayallow the water to enter rock matrix of the formation and mobilize thebitumen and/or extract hydrocarbon fluid from the bitumen. In someembodiments, the hydrocarbon fluid and/or hydrocarbons in thehydrocarbon fluid have a viscosity less than the viscosity of thebitumen. The extracted hydrocarbons and/or mobilized bitumen may beproduced from the section and/or be moved into other sections withsolvating fluids and/or pressurizing fluids. Extraction of hydrocarbonsfrom the bitumen and/or solvation of the bitumen with hot water and/or ahot solution may enhance hydrocarbon recovery from the formation. Forexample, extraction of bitumen may produce hydrocarbons having an APIgravity of at least 10°, at least 15° or at least 20°. The hydrocarbonsmay have a viscosity of at least 100 centipoise at 15° C. The qualityand/or type of the hydrocarbons produced from less heating incombination with hot water extraction may be improved as compared to thequality of hydrocarbons produced at higher temperatures.

In certain embodiments, first section 1060, second section 1062 and/orthird section 1064 may be treated with hydrocarbons (for example,naphtha, kerosene, diesel, vacuum gas oil, or a mixture thereof). Insome embodiments, the hydrocarbons have an aromatic content of at least1% by weight, at least 5% by weight, at least 10% by weight, at least20% by weight or at least 25% by weight. Hydrocarbons may be injectedinto a portion of first section 1060, second section 1062 and/or thirdsection 1064 through injection wells 788. In some embodiments, thehydrocarbons are produced from first section 1060 and/or other portionsof the formation. In certain embodiments, the hydrocarbons are producedfrom the formation, treated to remove heavy fractions of hydrocarbons(for example, asphaltenes, hydrocarbons having a boiling point of atleast 300° C., of at least 400° C., at least 500° C., or at least 600°C.) and the hydrocarbons are re-introduced into the formation. In someembodiments, one section may be treated with hydrocarbons while anothersection is treated with water. In some embodiments, water treatment of asection may be alternated with hydrocarbon treatment of the section. Insome embodiments, a first portion of hydrocarbons having a relativelyhigh boiling range distribution (for example, kerosene and/or diesel)are introduced in one section. A second portion of hydrocarbons having arelatively low boiling range distribution or hydrocarbons of loweconomic value (for example, propane) may be introduced into the sectionafter the first portion of hydrocarbons. The introduction ofhydrocarbons of different boiling range distributions may enhancerecovery of the higher boiling hydrocarbons and more economicallyvaluable hydrocarbons through production wells 206.

In an embodiment, a blend made from hydrocarbon mixtures produced fromfirst section 1060 is used as a solvation fluid. The blend may includeabout 20% by weight light hydrocarbons (or blending agent) or greater(for example, about 50% by weight or about 80% by weight lighthydrocarbons) and about 80% by weight heavy hydrocarbons or less (forexample, about 50% by weight or about 20% by weight heavy hydrocarbons).The weight percentage of light hydrocarbons and heavy hydrocarbons mayvary depending on, for example, a weight distribution (or API gravity)of light and heavy hydrocarbons, an aromatic content of thehydrocarbons, a relative stability of the blend, or a desired APIgravity of the blend. For example, the weight percentage of lighthydrocarbons in the blend may at most 50% by weight or at most 20% byweight. In certain embodiments, the weight percentage of lighthydrocarbons may be selected to mix the least amount of lighthydrocarbons with heavy hydrocarbons that produces a blend with adesired density or viscosity.

In some embodiments, polymers and/or monomers may be used as solvationfluids. Polymers and/or monomers may solvate and/or drive hydrocarbonsto allow mobilization of the hydrocarbons towards one or more productionwells. The polymer and/or monomer may reduce the mobility of a waterphase in pores of the hydrocarbon containing formation. The reduction ofwater mobility may allow the hydrocarbons to be more easily mobilizedthrough the hydrocarbon containing formation. Polymers that may be usedinclude, but are not limited to, polyacrylamides, partially hydrolyzedpolyacrylamide, polyacrylates, ethylenic copolymers, biopolymers,carboxymethylcellulose, polyvinyl alcohol, polystyrene sulfonates,polyvinylpyrrolidone, AMPS (2-acrylamide-2-methyl propane sulfonate), orcombinations thereof. Examples of ethylenic copolymers includecopolymers of acrylic acid and acrylamide, acrylic acid and laurylacrylate, lauryl acrylate and acrylamide. Examples of biopolymersinclude xanthan gum and guar gum. In some embodiments, polymers may becrosslinked in situ in the hydrocarbon containing formation. In otherembodiments, polymers may be generated in situ in the hydrocarboncontaining formation. Polymers and polymer preparations for use in oilrecovery are described in U.S. Pat. Nos. 6,439,308 to Wang; 6,417,268 toZhang et al.; 6,439,308 to Wang; 5,654,261 to Smith; 5,284,206 to Surleset al.; 5,199,490 to Surles et al.; and 5,103,909 to Morgenthaler etal., each of which is incorporated by reference as if fully set forthherein.

In some embodiments, the solvation fluid includes one or more nonionicadditives (for example, alcohols, ethoxylated alcohols, nonionicsurfactants and/or sugar based esters). In some embodiments, thesolvation fluid includes one or more anionic surfactants (for example,sulfates, sulfonates, ethoxylated sulfates, and/or phosphates).

In some embodiments, the solvation fluid includes carbon disulfide.Hydrogen sulfide, in addition to other sulfur compounds produced fromthe formation, may be converted to carbon disulfide using known methods.Suitable methods may include oxidizing sulfur compounds to sulfur and/orsulfur dioxide, and reacting sulfur and/or sulfur dioxide with carbonand/or a carbon containing compound to form carbon disulfide. Theconversion of the sulfur compounds to carbon disulfide and the use ofthe carbon disulfide for oil recovery are described in U.S. PatentPublication No. 2006-0254769 to Wang et al., which is incorporated byreference as if fully set forth herein. The carbon disulfide may beintroduced into first section 1060, second section 1062 and/or thirdsection 1064 as a solvation fluid.

In some embodiments, the solvation fluid is a hydrocarbon compound thatis capable of donating a hydrogen atom to the formation fluids. In someembodiments, the solvation fluid is capable of donating hydrogen to atleast a portion of the formation fluid, thus forming a mixture ofsolvating fluid and dehydrogenated solvating fluid mixture. Thesolvating fluid/dehydrogenated solvating fluid mixture may enhancesolvation and/or dissolution of a greater portion of the formationfluids as compared to the initial solvation fluid. Examples of suchhydrogen donating solvating fluids include, but are not limited to,tetralin, alkyl substituted tetralin, tetrahydroquinoline, alkylsubstituted hydroquinoline, 1,2-dihydronaphthalene, a distillate cuthaving at least 40% by weight naphthenic aromatic compounds, or mixturesthereof. In some embodiments, the hydrogen donating hydrocarbon compoundis tetralin.

In some embodiments, first section 1060, second section 1062 and/orthird section 1064 are heated to a temperature ranging form 175° C. to350° C. in the presence of the hydrogen donating solvating fluid. Atthese temperatures at least a portion of the formation fluids may behydrogenated by hydrogen donated from the hydrogen donating solvationfluid. In some embodiments, the minerals in the formation act as acatalyst for the hydrogenation process so that elevated formationtemperatures may not be necessary. Hydrogenation of at least a portionof the formation fluids may upgrade a portion of the formation fluidsand form a mixture of upgraded fluids and formation fluids. The mixturemay have a reduced viscosity compared to the initial formation fluids.In situ upgrading and the resulting reduction in viscosity mayfacilitate mobilization and/or recovery of the formation fluids. In situupgrading products that may be separated from the formation fluids atthe surface include, but are not limited to, naphtha, vacuum gas oil,distillate, kerosene, and/or diesel. Dehydrogenation of at least aportion of the hydrogen donating solvent may form a mixture that hasincreased polarity as compared to the initial hydrogen donating solvent.The increased polarity may enhance solvation or dissolution of a portionof the formation fluids and facilitate production and/or mobilization ofthe fluids to production wells 206.

In some embodiments, the hydrogen donating hydrocarbon compound isheated in a surface facility prior to being introduced into firstsection 1060, second section 1062 and/or third section 1064. Forexample, the hydrogen donating hydrocarbon compound may be heated to atemperature ranging from 100° C. to about 180° C., 120° C. to about 170°C., or from about 130 to 160° C. Heat from the hot hydrogen donatinghydrocarbon compound may facilitate mobilization, recovery and/orhydrogenation of fluids from first section 1060, second section 1062and/or third section 1064.

In some embodiments, a pressurizing fluid is provided in second section1062 and/or third section 1064 (for example, through injection wells788B, 788C) to increase mobilization of hydrocarbons within thesections. In some embodiments, a pressurizing fluid is provided tosecond section 1062 and/or third section 1064 in combination with thesolvation fluid to increase mobility of hydrocarbons within theformation. The pressurizing fluid may include gases such as carbondioxide, nitrogen, steam, methane, and/or mixtures thereof. In someembodiments, fluids produced from the formation (for example, combustiongases, heater exhaust gases, or produced formation fluids) may be usedas pressurizing fluid.

Providing a pressurizing fluid may increase a shear rate applied tohydrocarbon fluids in the formation and decrease the viscosity ofnon-Newtonian hydrocarbon fluids within the formation. In someembodiments, pressurizing fluid is provided to the selected sectionbefore significant heating of the formation. Pressurizing fluidinjection may increase the volume of the formation available forproduction. Pressurizing fluid injection may increase a ratio of energyoutput of the formation (energy content of products produced from theformation) to energy input into the formation (energy costs for treatingthe formation).

Providing the pressurizing fluid may increase a pressure in a selectedsection of the formation. The pressure in the selected section may bemaintained below a selected pressure. For example, the pressure may bemaintained below about 150 bars absolute, about 100 bars absolute, orabout 50 bars absolute. In some embodiments, the pressure may bemaintained below about 35 bars absolute. Pressure may be varieddepending on a number of factors (for example, desired production rateor an initial viscosity of tar in the formation). Injection of a gasinto the formation may result in a viscosity reduction of some of theformation fluids.

The pressurizing fluid may enhance the pressure gradient in theformation to flow mobilized hydrocarbons into first section 1060. Incertain embodiments, the production of fluids from first section 1060allows the pressure in second section 1062 and/or third section 1064 toremain below a selected pressure (for example, a pressure below whichfracturing of the overburden and/or the underburden may occur). In someembodiments, second section 1062 and/or third section 1064 have beenheated by heat transfer from first section 1060 prior to addition of thepressurizing fluid. In some embodiments, the pressurizing fluid is addedafter second section 1062 and/or third section 1064 have been heated toa desired temperature by residual heat from first section 1060.

In some embodiments, pressure is maintained by controlling flow of thepressurizing fluid into the selected section. In other embodiments, thepressure is controlled by varying a location or locations for injectingthe pressurizing fluid. In other embodiments, pressure is maintained bycontrolling a pressure and/or production rate at production wells 206A,206B and/or 206C. In some embodiments, the pressurized fluid (forexample, carbon dioxide) is separated from the produced fluids andre-introduced into the formation. After production has been stopped, thefluid may be sequestered in the formation.

In certain embodiments, formation fluid is produced from first section1060, second section 1062 and/or third section 1064. The formation fluidmay be produced through production wells 206A, 206B and/or 206C. Theformation fluid produced from second section 1062 and/or third section1064 may include solvation fluid; hydrocarbons from first section 1060,second section 1062 and/or third section 1064; and/or mixtures thereof.

Producing fluid from production wells in first section 1060 may lowerthe average pressure in the formation by forming an expansion volume formobilized fluids in adjacent sections of the formation. Producing fluidfrom production wells 206 in the first section 1060 may establish apressure gradient in the formation that draws mobilized fluid fromsecond section 1062 and/or third section 1064 into the first section.

Hydrocarbons may be produced from first section 1060, second section1062 and/or third section 1064 such that at least about 30%, at leastabout 40%, at least about 50%, at least about 60% or at least about 70%by volume of the initial mass of hydrocarbons in the formation areproduced. In certain embodiments, additional hydrocarbons may beproduced from the formation such that at least about 60%, at least about70%, or at least about 80% by volume of the initial volume ofhydrocarbons in the sections is produced from the formation through theaddition of solvation fluid.

Fluids produced from production wells described herein may betransported through conduits (pipelines) between the formation andtreatment facilities or refineries. The produced fluids may betransported through a pipeline to another location for furthertransportation (for example, the fluids can be transported to a facilityat a river or a coast through the pipeline where the fluids can befurther transported by tanker to a processing plant or refinery).Incorporation of selected solvation fluids and/or other produced fluids(for example, aromatic hydrocarbons) in the produced formation fluid maystabilize the formation fluid during transportation. In someembodiments, the solvation fluid is separated from the formation fluidsafter transportation to treatment facilities. In some embodiments, atleast a portion of the solvation fluid is separated from the formationfluids prior to transportation. In some embodiments, the fluids producedprior to solvent treatment include heavy hydrocarbons.

In some embodiments, the produced fluids may include at least 85%hydrocarbon liquids by volume and at most 15% gases by volume, at least90% hydrocarbon liquids by volume and at most 10% gases by volume, or atleast 95% hydrocarbon liquids by volume and at most 5% gases by volume.In some embodiments, the mixture produced after solvent and/or pressuretreatment includes solvation fluids, gases, bitumen, visbroken fluids,pyrolyzed fluids, or combinations thereof. The mixture may be separatedinto heavy hydrocarbon liquids, solvation fluid and/or gases. In someembodiments the heavy hydrocarbon liquids, solvation fluid and/orpressuring fluid (for example, carbon dioxide) are re-injected inanother section of the formation.

The heavy hydrocarbon liquids separated from the mixture may have an APIgravity of between 10° and 25°, between 15° and 24°, or between 19° and23°. In some embodiments, the separated hydrocarbon liquids may have anAPI gravity between 19° and 25°, between 20° and 24°, or between 210 and23°. A viscosity of the separated hydrocarbon liquids may be at most 350cp at 5° C. A P-value of the separated hydrocarbon liquids may be atleast 1.1, at least 1.5 or at least 2.0. The separated hydrocarbonliquids may have a bromine number of at most 3% and/or a CAPP number ofat most 2%. In some embodiments, the separated hydrocarbon liquids havean API gravity between 190 and 25°, a viscosity ranging at most 350 cpat 5° C., a P-value of at least 1.1, a CAPP number of at most 2% as1-decene equivalent, and/or a bromine number of at most 2%.

During an in situ heat treatment process, some formation fluid maymigrate outwards from the treatment area. The formation fluid mayinclude benzene and/or other contaminants. Some portions of theformation that contaminants migrate to will be subsequently treated whena new treatment area is defined and processed using the in situ heattreatment process. Such contaminants may be removed or destroyed by thesubsequent in situ heat treatment process. Some areas of the formationto which contaminants migrate may not become part of a new treatmentarea subjected to in situ heat treatment. Migration inhibition systemsmay be implemented to inhibit contaminants from migrating to areas inthe formation that are not to be subjected to in situ heat treatment.

In some embodiments, a barrier (for example, a low temperature zone orfreeze barrier) surrounds at least a portion of the perimeter of atreatment area. The barrier may be 20 m to 100 m from the closestheaters in the treatment area used in the in situ heat treatment processto heat the formation. Some contaminants may migrate outwards as vaportowards the barrier through fractures or permeable zones. Some of thecontaminants may condense in the formation.

In some in situ heat treatment embodiments, a migration inhibitionsystem may be used to minimize or eliminate migration of formation fluidfrom the treatment area of the in situ heat treatment process. FIG. 286depicts a representation of a fluid migration inhibition system. Barrier1058 may surround treatment area 1028. Migration inhibition wells 1066may be placed in the formation between barrier 1058 and treatment area1028. Migration inhibition wells 1066 may be offset from wells used toheat the formation and/or from production wells used to produce fluidfrom the formation. Migration inhibition wells 1066 may be placed information that is below pyrolysis and/or dissociation temperatures ofminerals in the formation.

In some embodiments, one or more of the migration inhibition wells 1066include heaters. The heaters may be used to heat portions of theformation adjacent to the wells to a relatively low temperature. Therelatively low temperature may be a temperature below a dissociationtemperature of minerals in the formation adjacent to the well or below apyrolysis temperature of hydrocarbons in the formation. The temperaturethat the low temperature heater wells raise the formation to may be lessthan 260° C., less than 230° C., or less than 200° C. In someembodiments, heating elements in migration inhibition wells 1066 may betailored so that the heating elements only heat portions of theformation that have permeability sufficient to allow for the migrationof fluid (for example, fracture systems) and/or to allow forintroduction of fluid from the migration inhibition wells.

In some embodiments, one or more heater wells may be installed adjacentto the migration inhibition wells 1066. The heater wells may heatadjacent formation to an average temperature less than the dissociationtemperature of minerals in the formation and/or less than the pyrolysistemperature of hydrocarbons in the formation. The heater wells mayincrease the permeability of the formation adjacent to migrationinhibition wells 1066. Heating elements in the heater wells may betailored to only heat portions of the formation that have permeabilitysufficient to allow for migration of fluid and/or introduction of fluidfrom migration inhibition wells 1066 into the formation.

The heat supplied by heaters near or from the migration inhibition wellsmay inhibit condensation of migrating vapors located adjacent to themigration inhibition wells. Sweep fluid introduced into the formationthrough the migration inhibition wells may drive migrating vapors backto the heated treatment area. At least a portion of the migrating vaporsreturned to the treatment area may react in the treatment area. At leasta portion of the migrating vapors returned to the treatment area may beproduced from the formation through production wells.

Some or all migration inhibition wells 1066 may be injector wells thatallow for the introduction of a sweep fluid into the formation. Theinjector wells may include smart well technology. Sweep fluid may beintroduced into the formation through critical orifices, perforations orother types of openings in the injector wells. In some embodiments, thesweep fluid is carbon dioxide. The carbon dioxide may be carbon dioxideproduced from an in situ heat treatment process. The sweep fluid may beor include other fluids, such as nitrogen, methane or othernon-condensable hydrocarbons, exhaust gases, air, water, and/or steam.The sweep fluid may provide positive pressure in the formation outsideof treatment area 1028. The positive pressure may inhibit migration offormation fluid from treatment area 1028 towards barrier 1058. The sweepfluid may move through fractures in the formation toward or intotreatment area 1028. The sweep fluid may carry fluids that have migratedaway from treatment area 1028 back to the treatment area. The pressureof the fluid introduced through migration inhibition wells 1066 may bemaintained below the fracture pressure of the formation.

After an in situ process, energy recovery, remediation, and/orsequestration of carbon dioxide or other fluids in the treated area; thetreatment area may still be at an elevated temperature. Sulfur may beintroduced into the formation to act as a drive fluid to removeremaining formation fluid from the formation. The sulfur may beintroduced through outermost wellbores in the formation. The wellboresmay be injection wells, production wells, monitor wells, heater wells,barrier wells, or other types of wells that are converted to use assulfur injection wells. The sulfur may be used to drive fluid inwardstowards production wells in the pattern of wells used during the in situheat treatment process. The wells used as production wells for sulfurmay be production wells, heater wells, injection wells, monitor wells,or other types of wells converted for use as sulfur production wells.

In some embodiments, sulfur may be introduced in the treatment area froman outermost set of wells. Formation fluid may be produced from a firstinward set of wellbores until substantially only sulfur is produced fromthe first inward set of wells. The first inward set of wells may beconverted to injection wells. Sulfur may be introduced in the firstinward set of wells to drive remaining formation fluid towards a secondinward set of wells. The pattern may be continued until sulfur has beenintroduced into all of the treatment area. In some embodiments, a linedrive may be used for introducing the sulfur into the treatment area.

In some embodiments, molten sulfur may be injected into the treatmentarea. The molten sulfur may act as a displacement agent that movesand/or entrains remaining fluid in the treatment area. The molten sulfurmay be injected into the formation from selected wells. The sulfur maybe at a temperature near a melting point of sulfur so that the sulfurhas a relatively low viscosity. In some embodiments, the formation maybe at a temperature above the boiling point of sulfur. Sulfur may beintroduced into the formation as a gas or as a liquid.

Sulfur may be introduced into the formation until substantially onlysulfur is produced from the last sulfur production well or productionwells. When substantially only sulfur is produced from the last sulfurproduction well or production wells, introduction of additional sulfurmay be stopped, and the production from the production well orproduction wells may be stopped. Sulfur in the formation may be allowedto remain in the formation and solidify.

Alternative energy sources may be used to supply electricity forsubsurface electric heaters. Alternative energy sources include, but arenot limited to, wind, off-peak power, hydroelectric power, geothermal,solar, and tidal wave action. Some of these alternative energy sourcesprovide intermittent, time-variable power, or power-variable power. Toprovide power for subsurface electric heaters, power provided by thesealternative energy sources may be conditioned to produce power withappropriate operating parameters (for example, voltage, frequency,and/or current) for the subsurface heaters.

FIG. 287 depicts an embodiment for generating electricity for subsurfaceheaters from an intermittent power source. The generated electricalpower may be used to power other equipment used to treat a subsurfaceformation such as, but not limited to, pumps, computers, or otherelectrical equipment. In certain embodiments, windmill 1068 is used togenerate electricity to power heaters 802. Windmill 1068 may representone or more windmills in a wind farm. The windmills convert wind to ausable mechanical form of motion. In some embodiments, the wind farm mayinclude advanced windmills as suggested by the National Renewable EnergyLaboratory (Golden, Colo., U.S.A.). In some embodiments, windmill 1068varies its power output during a 24 hour period (for example, thewindmill may generate the most power at night). Using windmill 1068 asthe power source may reduce the carbon dioxide footprint for supplyingpower to heaters 802. In some embodiments, windmill 1068 includes otherintermittent, time-variable, or power-variable power sources.

In some embodiments, gas turbine 1070 is used to generate electricity topower heaters 802. Windmill 1068 and/or gas turbine 1070 may be coupledto transformer 1072. Transformer 1072 may convert power from windmill1068 and/or gas turbine 1070 into electrical power with appropriateoperating parameters for heaters 802 (for example, AC or DC power withappropriate voltage, current, and/or frequency may be generated by thetransformer).

In certain embodiments, tap controller 1074 is coupled to transformer1072, control system 1076, and heaters 802. Tap controller 1074 maymonitor and control transformer 1072 to maintain a constant voltage toheaters 802, regardless of the load of the heaters. Tap controller 1074may control power output in a range from 5 MVA (megavolt amps) to 500MVA, from 10 MVA to 400 MVA, or from 20 MVA to 300 MVA. Tap controller1074 may be designed to meet selected design requirements such as, butnot limited to, load limitations of components (such as transformer1072, control system 1076, and/or heaters 802) and the expected fullload current in the electrical circuit. Tap controller 1074 may be anelectromechanical, mechanical, electrical, electromagnetic, or solidstate tap controller. In one embodiments, tap controller 1074 is a 32step (±16 steps) electromechanical tap controller obtained from ABB Ltd.(Asea Brown Boveri) (Zurich, Switzerland). Tap controller 1074 may be astep controller that changes power in steps over a period of time (forexample, 1 step per minute). Tap controller 1074 may operated over apercentage of the total range (for example, ±15% of the voltage or ±10%of the voltage).

As an example, during operation, an overload of voltage may be sent fromtransformer 1072. Tap controller 1074 may modify the load provided toheaters 802 and distribute the excess load to other heaters and/or otherequipment in need of power. In some embodiments, tap controller 1074 maystore the excess load for future use.

Control system 1076 may control tap controller 1074. Control system 1076may be, for example, a computer controller or an analog logic system.Control system 1076 may use data supplied from power sensors 1078 togenerate predictive algorithms and/or control tap controller 1074. Forexample, data may be an amount of power generated from windmill 1068,gas turbine 1070, and/or transformer 1072. Data may also include anamount of resistive load of heaters 802. Power sensors 1078 may betoroidal current sensors that output voltages that are proportional tothe currents in wires passing through the sensors.

Automatic voltage regulation for resistive load of a heater enhances thelife of the heaters and/or allows constant heat output from the heatersto a subsurface formation. Adjusting the load demands instead ofadjusting the power source allows enhanced control of power supplied toheaters and/or other equipment that requires electricity. Power suppliedto heaters 802 may be controlled within selected limits (for example, apower supplied and/or controlled to a heater within 1%, 5%, 10%, or 20%of power required by the heater). Control of power supplied fromalternative energy sources may allow output of prime power at itsrating, allow energy produced (for example, from an intermittent source,a subsurface formation, or a hydroelectric source) to be stored and usedlater, and/or allow use of power generated by intermittent power sourcesto be used as a constant source of energy.

Some hydrocarbon containing formations, such as oil shale formations,may include nahcolite, trona, dawsonite, and/or other minerals withinthe formation. In some embodiments, nahcolite is contained in partiallyunleached or unleached portions of the formation. Unleached portions ofthe formation are parts of the formation where minerals have not beenremoved by groundwater in the formation. For example, in the Piceancebasin in Colorado, U.S.A., unleached oil shale is found below a depth ofabout 500 m below grade. Deep unleached oil shale formations in thePiceance basin center tend to be relatively rich in hydrocarbons. Forexample, about 0.10 liters to about 0.15 liters of oil per kilogram(L/kg) of oil shale may be producible from an unleached oil shaleformation.

Nahcolite is a mineral that includes sodium bicarbonate (NaHCO₃).Nahcolite may be found in formations in the Green River lakebeds inColorado, U.S.A. In some embodiments, at least about 5 weight %, atleast about 10 weight %, or at least about 20 weight % nahcolite may bepresent in the formation. Dawsonite is a mineral that includes sodiumaluminum carbonate (NaAl(CO₃)(OH)₂). Dawsonite is typically present inthe formation at weight percents greater than about 2 weight % or, insome embodiments, greater than about 5 weight %. Nahcolite and/ordawsonite may dissociate at temperatures used in an in situ heattreatment process. The dissociation is strongly endothermic and mayproduce large amounts of carbon dioxide.

Nahcolite and/or dawsonite may be solution mined prior to, during,and/or following treatment of the formation in situ to avoiddissociation reactions and/or to obtain desired chemical compounds. Incertain embodiments, hot water or steam is used to dissolve nahcolite insitu to form an aqueous sodium bicarbonate solution before the in situheat treatment process is used to process hydrocarbons in the formation.Nahcolite may form sodium ions (Na+) and bicarbonate ions (HCO₃—) inaqueous solution. The solution may be produced from the formationthrough production wells, thus avoiding dissociation reactions duringthe in situ heat treatment process. In some embodiments, dawsonite isthermally decomposed to alumina during the in situ heat treatmentprocess for treating hydrocarbons in the formation. The alumina issolution mined after completion of the in situ heat treatment process.

Production wells and/or injection wells used for solution mining and/orfor in situ heat treatment processes may include smart well technology.The smart well technology allows the first fluid to be introduced at adesired zone in the formation. The smart well technology allows thesecond fluid to be removed from a desired zone of the formation.

Formations that include nahcolite and/or dawsonite may be treated usingthe in situ heat treatment process. A perimeter barrier may be formedaround the portion of the formation to be treated. The perimeter barriermay inhibit migration of water into the treatment area. During solutionmining and/or the in situ heat treatment process, the perimeter barriermay inhibit migration of dissolved minerals and formation fluid from thetreatment area. During initial heating, a portion of the formation to betreated may be raised to a temperature below the dissociationtemperature of the nahcolite. The temperature may be at most about 90°C., or in some embodiments, at most about 80° C. The temperature may beany temperature that increases the solvation rate of nahcolite in water,but is also below a temperature at which nahcolite dissociates (aboveabout 95° C. at atmospheric pressure).

A first fluid may be injected into the heated portion. The first fluidmay include water, brine, steam, or other fluids that form a solutionwith nahcolite and/or dawsonite. The first fluid may be at an increasedtemperature, for example, about 90° C., about 95° C., or about 100° C.The increased temperature may be similar to the temperature of theportion of the formation.

In some embodiments, the first fluid is injected at an increasedtemperature into a portion of the formation that has not been heated byheat sources. The increased temperature may be a temperature below aboiling point of the first fluid, for example, about 90° C. for water.Providing the first fluid at an increased temperature increases atemperature of a portion of the formation. In certain embodiments,additional heat may be provided from one or more heat sources in theformation during and/or after injection of the first fluid.

In other embodiments, the first fluid is or includes steam. The steammay be produced by forming steam in a previously heated portion of theformation (for example, by passing water through u-shaped wellbores thathave been used to heat the formation), by heat exchange with fluidsproduced from the formation, and/or by generating steam in standardsteam production facilities. In some embodiments, the first fluid may befluid introduced directly into a hot portion of the portion and producedfrom the hot portion of the formation. The first fluid may then be usedas the first fluid for solution mining.

In some embodiments, heat from a hot previously treated portion of theformation is used to heat water, brine, and/or steam used for solutionmining a new portion of the formation. Heat transfer fluid may beintroduced into the hot previously treated portion of the formation. Theheat transfer fluid may be water, steam, carbon dioxide, and/or otherfluids. Heat may transfer from the hot formation to the heat transferfluid. The heat transfer fluid is produced from the formation throughproduction wells. The heat transfer fluid is sent to a heat exchanger.The heat exchanger may heat water, brine, and/or steam used as the firstfluid to solution mine the new portion of the formation. The heattransfer fluid may be reintroduced into the heated portion of theformation to produce additional hot heat transfer fluid. In someembodiments, heat transfer fluid produced from the formation is treatedto remove hydrocarbons or other materials before being reintroduced intothe formation as part of a remediation process for the heated portion ofthe formation.

Steam injected for solution mining may have a temperature below thepyrolysis temperature of hydrocarbons in the formation. Injected steammay be at a temperature below 250° C., below 300° C., or below 400° C.The injected steam may be at a temperature of at least 150° C., at least135° C., or at least 125° C. Injecting steam at pyrolysis temperaturesmay cause problems as hydrocarbons pyrolyze and hydrocarbon fines mixwith the steam. The mixture of fines and steam may reduce permeabilityand/or cause plugging of production wells and the formation. Thus, theinjected steam temperature is selected to inhibit plugging of theformation and/or wells in the formation.

The temperature of the first fluid may be varied during the solutionmining process. As the solution mining progresses and the nahcolitebeing solution mined is farther away from the injection point, the firstfluid temperature may be increased so that steam and/or water thatreaches the nahcolite to be solution mined is at an elevated temperaturebelow the dissociation temperature of the nahcolite. The steam and/orwater that reaches the nahcolite is also at a temperature below atemperature that promotes plugging of the formation and/or wells in theformation (for example, the pyrolysis temperature of hydrocarbons in theformation).

A second fluid may be produced from the formation following injection ofthe first fluid into the formation. The second fluid may includematerial dissolved in the first fluid. For example, the second fluid mayinclude carbonic acid or other hydrated carbonate compounds formed fromthe dissolution of nahcolite in the first fluid. The second fluid mayalso include minerals and/or metals. The minerals and/or metals mayinclude sodium, aluminum, phosphorus, and other elements.

Solution mining the formation before the in situ heat treatment processallows initial heating of the formation to be provided by heat transferfrom the first fluid used during solution mining. Solution miningnahcolite or other minerals that decompose or dissociate by means ofendothermic reactions before the in situ heat treatment process avoidshaving energy supplied to heat the formation being used to support theseendothermic reactions. Solution mining allows for production of mineralswith commercial value. Removing nahcolite or other minerals before thein situ heat treatment process removes mass from the formation. Thus,less mass is present in the formation that needs to be heated to highertemperatures and heating the formation to higher temperatures may beachieved more quickly and/or more efficiently. Removing mass from theformation also may increase the permeability of the formation.Increasing the permeability may reduce the number of production wellsneeded for the in situ heat treatment process. In certain embodiments,solution mining before the in situ heat treatment process reduces thetime delay between startup of heating of the formation and production ofhydrocarbons by two years or more.

FIG. 288 depicts an embodiment of solution mining well 1080. Solutionmining well 1080 may include insulated portion 1082, input 1084, packer1086, and return 1088. Insulated portion 1082 may be adjacent tooverburden 482 of the formation. In some embodiments, insulated portion1082 is low conductivity cement. The cement may be low density, lowconductivity vermiculite cement or foam cement. Input 1084 may directthe first fluid to treatment area 1028. Perforations or other types ofopenings in input 1084 allow the first fluid to contact formationmaterial in treatment area 1028. Packer 1086 may be a bottom seal forinput 1084. First fluid passes through input 1084 into the formation.First fluid dissolves minerals and becomes second fluid. The secondfluid may be denser than the first fluid. An entrance into return 1088is typically located below the perforations or openings that allow thefirst fluid to enter the formation. Second fluid flows to return 1088.The second fluid is removed from the formation through return 1088.

FIG. 289 depicts a representation of an embodiment of solution miningwell 1080. Solution mining well 1080 may include input 1084 and return1088 in casing 1090. Input 1084 and/or return 1088 may be coiled tubing.

FIG. 290 depicts a representation of an embodiment of solution miningwell 1080. Insulating portions 1082 may surround return 1088. Input 1084may be positioned in return 1088. In some embodiments, input 1084 mayintroduce the first fluid into the treatment area below the entry pointinto return 1088. In some embodiments, crossovers may be used to directfirst fluid flow and second fluid flow so that first fluid is introducedinto the formation from input 1084 above the entry point of second fluidinto return 1088.

FIG. 291 depicts an elevational view of an embodiment of wells used forsolution mining and/or for an in situ heat treatment process. Solutionmining wells 1080 may be placed in the formation in an equilateraltriangle pattern. In some embodiments, the spacing between solutionmining wells 1080 may be about 36 m. Other spacings may be used. Heatsources 202 may also be placed in an equilateral triangle pattern.Solution mining wells 1080 substitute for certain heat sources of thepattern. In the shown embodiment, the spacing between heat sources 202is about 9 m. The ratio of solution mining well spacing to heat sourcespacing is 4. Other ratios may be used if desired. After solution miningis complete, solution mining wells 1080 may be used as production wellsfor the in situ heat treatment process.

In some formations, a portion of the formation with unleached mineralsmay be below a leached portion of the formation. The unleached portionmay be thick and substantially impermeable. A treatment area may beformed in the unleached portion. Unleached portion of the formation tothe sides, above and/or below the treatment area may be used as barriersto fluid flow into and out of the treatment area. A first treatment areamay be solution mined to remove minerals, increase permeability in thetreatment area, and/or increase the richness of the hydrocarbons in thetreatment area. After solution mining the first treatment area, in situheat treatment may be used to treat a second treatment area. In someembodiments, the second treatment area is the same as the firsttreatment area. In some embodiments, the second treatment has a smallervolume than the first treatment area so that heat provided by outermostheat sources to the formation do not raise the temperature of unleachedportions of the formation to the dissociation temperature of theminerals in the unleached portions.

In some embodiments, a leached or partially leached portion of theformation above an unleached portion of the formation may includesignificant amounts of hydrocarbon materials. An in situ heating processmay be used to produce hydrocarbon fluids from the unleached portionsand the leached or partially leached portions of the formation. FIG. 292depicts a representation of a formation with unleached zone 1092 belowleached zone 1094. Unleached zone 1092 may have an initial permeabilitybefore solution mining of less than 0.1 millidarcy. Solution miningwells 1080 may be placed in the formation. Solution mining wells 1080may include smart well technology that allows the position of firstfluid entrance into the formation and second flow entrance into thesolution mining wells to be changed. Solution mining wells 1080 may beused to form first treatment area 1028′ in unleached zone 1092.Unleached zone 1092 may initially be substantially impermeable.Unleached portions of the formation may form a top barrier and sidebarriers around first treatment area 1028′. After solution mining firsttreatment area 1028′, the portions of solution mining wells 1080adjacent to the first treatment area may be converted to productionwells and/or heater wells.

Heat sources 202 in first treatment area 1028′ may be used to heat thefirst treatment area to pyrolysis temperatures. In some embodiments, oneor more heat sources 202 are placed in the formation before firsttreatment area 1028′ is solution mined. The heat sources may be used toprovide initial heating to the formation to raise the temperature of theformation and/or to test the functionality of the heat sources. In someembodiments, one or more heat sources are installed during solutionmining of the first treatment area, or after solution mining iscompleted. After solution mining, heat sources 202 may be used to raisethe temperature of at least a portion of first treatment area 1028′above the pyrolysis and/or mobilization temperature of hydrocarbons inthe formation to result in the generation of mobile hydrocarbons in thefirst treatment area.

Barrier wells 200 may be introduced into the formation. Ends of barrierwells 200 may extend into and terminate in unleached zone 1092.Unleached zone 1092 may be impermeable. In some embodiments, barrierwells 200 are freeze wells. Barrier wells 200 may be used to form abarrier to fluid flow into or out of unleached zone 1094. Barrier wells200, overburden 482, and the unleached material above first treatmentarea 1028′ may define second treatment area 1028″. In some embodiments,a first fluid may be introduced into second treatment area 1028″ throughsolution mining wells 1080 to raise the initial temperature of theformation in second treatment area 1028″ and remove any residual solubleminerals from the second treatment area. In some embodiments, the topbarrier above first treatment area 1028′ may be solution mined to removeminerals and combine first treatment area 1028′ and second treatmentarea 1028″ into one treatment area. After solution mining, heat sourcesmay be activated to heat the treatment area to pyrolysis temperatures.

FIG. 293 depicts an embodiment for solution mining the formation.Barrier 1058 (for example, a frozen barrier and/or a grout barrier) maybe formed around a perimeter of treatment area 1028 of the formation.The footprint defined by the barrier may have any desired shape such ascircular, square, rectangular, polygonal, or irregular shape. Barrier1058 may be any barrier formed to inhibit the flow of fluid into or outof treatment area 1028. For example, barrier 1058 may include one ormore freeze wells that inhibit water flow through the barrier. Barrier1058 may be formed using one or more barrier wells 200. Formation ofbarrier 1058 may be monitored using monitor wells 1096 and/or bymonitoring devices placed in barrier wells 200.

Water inside treatment area 1028 may be pumped out of the treatment areathrough injection wells 788 and/or production wells 206. In certainembodiments, injection wells 788 are used as production wells 206 andvice versa (the wells are used as both injection wells and productionwells). Water may be pumped out until a production rate of water is lowor stops.

Heat may be provided to treatment area 1028 from heat sources 202. Heatsources may be operated at temperatures that do not result in thepyrolysis of hydrocarbons in the formation adjacent to the heat sources.In some embodiments, treatment area 1028 is heated to a temperature fromabout 90° C. to about 120° C. (for example, a temperature of about 90°C., 95° C., 100° C., 110° C., or 120° C.). In certain embodiments, heatis provided to treatment area 1028 from the first fluid injected intothe formation. The first fluid may be injected at a temperature fromabout 90° C. to about 120° C. (for example, a temperature of about 90°C., 95° C., 100° C., 110° C., or 120° C.). In some embodiments, heatsources 202 are installed in treatment area 1028 after the treatmentarea is solution mined. In some embodiments, some heat is provided fromheaters placed in injection wells 788 and/or production wells 206. Atemperature of treatment area 1028 may be monitored using temperaturemeasurement devices placed in monitoring wells 1096 and/or temperaturemeasurement devices in injection wells 788, production wells 206, and/orheat sources 202.

The first fluid is injected through one or more injection wells 788. Insome embodiments, the first fluid is hot water. The first fluid may mixand/or combine with non-hydrocarbon material that is soluble in thefirst fluid, such as nahcolite, to produce a second fluid. The secondfluid may be removed from the treatment area through injection wells788, production wells 206, and/or heat sources 202. Injection wells 788,production wells 206, and/or heat sources 202 may be heated duringremoval of the second fluid. Heating one or more wells during removal ofthe second fluid may maintain the temperature of the fluid duringremoval of the fluid from the treatment area above a desired value.After producing a desired amount of the soluble non-hydrocarbon materialfrom treatment area 1028, solution remaining within the treatment areamay be removed from the treatment area through injection wells 788,production wells 206, and/or heat sources 202. The desired amount of thesoluble non-hydrocarbon material may be less than half of the solublenon-hydrocarbon material, a majority of the soluble non-hydrocarbonmaterial, substantially all of the soluble non-hydrocarbon material, orall of the soluble non-hydrocarbon material. Removing solublenon-hydrocarbon material may produce a relatively high permeabilitytreatment area 1028.

Hydrocarbons within treatment area 1028 may be pyrolyzed and/or producedusing the in situ heat treatment process following removal of solublenon-hydrocarbon materials. The relatively high permeability treatmentarea allows for easy movement of hydrocarbon fluids in the formationduring in situ heat treatment processing. The relatively highpermeability treatment area provides an enhanced collection area forpyrolyzed and mobilized fluids in the formation. During the in situ heattreatment process, heat may be provided to treatment area 1028 from heatsources 202. A mixture of hydrocarbons may be produced from theformation through production wells 206 and/or heat sources 202. Incertain embodiments, injection wells 788 are used as either productionwells and/or heater wells during the in situ heat treatment process.

In some embodiments, a controlled amount of oxidant (for example, airand/or oxygen) is provided to treatment area 1028 at or near heatsources 202 when a temperature in the formation is above a temperaturesufficient to support oxidation of hydrocarbons. At such a temperature,the oxidant reacts with the hydrocarbons to provide heat in addition toheat provided by electrical heaters in heat sources 202. The controlledamount of oxidant may facilitate oxidation of hydrocarbons in theformation to provide additional heat for pyrolyzing hydrocarbons in theformation. The oxidant may more easily flow through treatment area 1028because of the increased permeability of the treatment area afterremoval of the non-hydrocarbon materials. The oxidant may be provided ina controlled manner to control the heating of the formation. The amountof oxidant provided is controlled so that uncontrolled heating of theformation is avoided. Excess oxidant and combustion products may flow toproduction wells in treatment area 1028.

Following the in situ heat treatment process, treatment area 1028 may becooled by introducing water to produce steam from the hot portion of theformation. Introduction of water to produce steam may vaporize somehydrocarbons remaining in the formation. Water may be injected throughinjection wells 788. The injected water may cool the formation. Theremaining hydrocarbons and generated steam may be produced throughproduction wells 206 and/or heat sources 202. Treatment area 1028 may becooled to a temperature near the boiling point of water. The steamproduced from the formation may be used to heat a first fluid used tosolution mine another portion of the formation.

Treatment area 1028 may be further cooled to a temperature at whichwater will condense in the formation. Water and/or solvent may beintroduced into and be removed from the treatment area. Removing thecondensed water and/or solvent from treatment area 1028 may remove anyadditional soluble material remaining in the treatment area. The waterand/or solvent may entrain non-soluble fluid present in the formation.Fluid may be pumped out of treatment area 1028 through production well206 and/or heat sources 202. The injection and removal of water and/orsolvent may be repeated until a desired water quality within treatmentarea 1028 is achieved. Water quality may be measured at the injectionwells, heat sources 202, and/or production wells. The water quality maysubstantially match or exceed the water quality of treatment area 1028prior to treatment.

In some embodiments, treatment area 1028 may include a leached zonelocated above an unleached zone. The leached zone may have been leachednaturally and/or by a separate leaching process. In certain embodiments,the unleached zone may be at a depth of at least about 500 m. Athickness of the unleached zone may be between about 100 m and about 500m. However, the depth and thickness of the unleached zone may varydepending on, for example, a location of treatment area 1028 and/or thetype of formation. In certain embodiments, the first fluid is injectedinto the unleached zone below the leached zone. Heat may also beprovided into the unleached zone.

In certain embodiments, a section of a formation may be left untreatedby solution mining and/or unleached. The unleached section may beproximate a selected section of the formation that has been leachedand/or solution mined by providing the first fluid as described above.The unleached section may inhibit the flow of water into the selectedsection. In some embodiments, more than one unleached section may beproximate a selected section.

Nahcolite may be present in the formation in layers or beds. Prior tosolution mining, such layers may have little or no permeability. Incertain embodiments, solution mining layered or bedded nahcolite fromthe formation causes vertical shifting in the formation. FIG. 294depicts an embodiment of a formation with nahcolite layers in theformation below overburden 482 and before solution mining nahcolite fromthe formation. Hydrocarbon layers 484A have substantially no nahcoliteand hydrocarbon layers 484B have nahcolite. FIG. 295 depicts theformation of FIG. 294 after the nahcolite has been solution mined.Layers 484B have collapsed due to the removal of the nahcolite from thelayers. The collapsing of layers 484B causes compaction of the layersand vertical shifting of the formation. The hydrocarbon richness oflayers 484B is increased after compaction of the layers. In addition,the permeability of layers 484B may remain relatively high aftercompaction due to removal of the nahcolite. The permeability may be morethan 5 darcy, more than 1 darcy, or more than 0.5 darcy after verticalshifting. The permeability may provide fluid flow paths to productionwells when the formation is treated using an in situ heat treatmentprocess. The increased permeability may allow for a large spacingbetween production wells. Distances between production wells for the insitu heat treatment system after solution mining may be greater than 10m, greater than 20 m, or greater than 30 meters. Heater wells may beplaced in the formation after removal of nahcolite and the subsequentvertical shifting. Forming heater wellbores and/or installing heaters inthe formation after the vertical shifting protects the heaters frombeing damaged due to the vertical shifting.

In certain embodiments, removing nahcolite from the formationinterconnects two or more wells in the formation. Removing nahcolitefrom zones in the formation may increase the permeability in the zones.Some zones may have more nahcolite than others and become more permeableas the nahcolite is removed. At a certain time, zones with the increasedpermeability may interconnect two or more wells (for example, injectionwells or production wells) in the formation.

FIG. 296 depicts an embodiment of two injection wells interconnected bya zone that has been solution mined to remove nahcolite from the zone.Solution mining wells 1080 are used to solution mine hydrocarbon layer484, which contains nahcolite. During the initial portion of thesolution mining process, solution mining wells 1080 are used to injectwater and/or other fluids, and to produce dissolved nahcolite fluidsfrom the formation. Each solution mining well 1080 is used to injectwater and produce fluid from a near wellbore region as the permeabilityof hydrocarbon layer is not sufficient to allow fluid to flow betweenthe injection wells. In certain embodiments, zone 1098 has morenahcolite than other portions of hydrocarbon layer 484. With increasednahcolite removal from zone 1098, the permeability of the zone mayincrease. The permeability increases from the wellbores outwards asnahcolite is removed from zone 1098. At some point during solutionmining of the formation, the permeability of zone 1098 increases toallow solution mining wells 1080 to become interconnected such thatfluid will flow between the wells. At this time, one solution miningwell 1080 may be used to inject water while the other solution miningwell is used to produce fluids from the formation in a continuousprocess. Injecting in one well and producing from a second well may bemore economical and more efficient in removing nahcolite, as compared toinjecting and producing through the same well. In some embodiments,additional wells may be drilled into zone 1098 and/or hydrocarbon layer484 in addition to solution mining wells 1080. The additional wells maybe used to circulate additional water and/or to produce fluids from theformation. The wells may later be used as heater wells and/or productionwells for the in situ heat treatment process treatment of hydrocarbonlayer 484.

In some embodiments, a treatment area has nahcolite beds above and/orbelow the treatment area. The nahcolite beds may be relatively thin (forexample, about 5 m to about 10 m in thickness). In an embodiment, thenahcolite beds are solution mined using horizontal solution mining wellsin the nahcolite beds. The nahcolite beds may be solution mined in ashort amount of time (for example, in less than 6 months). Aftersolution mining of the nahcolite beds, the treatment area and thenahcolite beds may be heated using one or more heaters. The heaters maybe placed either vertically, horizontally, or at other angles within thetreatment area and the nahcolite beds. The nahcolite beds and thetreatment area may then undergo the in situ heat treatment process.

In some embodiments, the solution mining wells in the nahcolite beds areconverted to production wells. The production wells may be used toproduce fluids during the in situ heat treatment process. Productionwells in the nahcolite bed above the treatment area may be used toproduce vapors or gas (for example, gas hydrocarbons) from theformation. Production wells in the nahcolite bed below the treatmentarea may be used to produce liquids (for example, liquid hydrocarbons)from the formation.

FIG. 297 depicts a representation of an embodiment for treating aportion of a formation having hydrocarbon containing layer 484 betweenupper nahcolite bed 1978 and lower nahcolite bed 1978′. In anembodiment, nahcolite beds 1978, 1978′ have thicknesses of about 5 m andinclude relatively large amounts of nahcolite (for example, over about50 weight percent nahcolite. In the embodiment, hydrocarbon containinglayer 484 is at a depth of over 595 meters below the surface, has athickness of 40 m or more and has oil shale with an average richness ofover 100 liters per metric ton. Hydrocarbon containing layer 484 maycontain relatively little nahcolite, though the hydrocarbon containinglayer may contain some seams of nahcolite typically with thicknessesless than 3 m.

Solution mining wells 1080 may be formed in nahcolite beds 1978, 1978′(i.e., into and out of the page as depicted in FIG. 297). FIG. 298depicts a representation of a portion of the formation that isorthogonal to the formation depicted in FIG. 297 and passes through oneof solution mining wells 1080 in nahcolite bed 1978. Solution miningwells 1080 may be spaced apart by 25 m or more. Hot water and/or steammay be circulated into the formation from solution mining wells 1080 todissolve nahcolite in nahcolite beds 1978, 1978′. Dissolved nahcolitemay be produced from the formation through solution mining wells 1080.After completion of solution mining, production liners may be installedin one or more of the solution mining wells 1080 and the solution miningwells may be converted to production wells for an in situ heat treatmentprocess used to produce hydrocarbons from hydrocarbon containing layer484.

Before, during or after solution mining of nahcolite beds 1978, 1978′,heater wellbores 428 may be formed in the formation in a pattern (forexample, in a triangular pattern as depicted in FIG. 298 with wellboresgoing into and out of the page). As depicted in FIG. 297, portions ofheater wellbores 428 may pass through nahcolite bed 1978. Portions ofheater wellbores 428 may pass into or through nahcolite bed 1978′.Heaters wellbores 428 may be oriented at an angle (as depicted in FIG.297), oriented vertically, or oriented substantially horizontally if thenahcolite layers dip. Heaters may be placed in heater wellbores 428.Heating sections of the heaters may provide heat to hydrocarboncontaining layer 484. The wellbore pattern may allow superposition ofheat from the heaters to raise the temperature of hydrocarbon containinglayer 484 to a desired temperature in a reasonable amount of time.

Packers, cement, or other sealing systems may be used to inhibitformation fluid from moving up wellbores 428 past an upper portion ofnahcolite bed 1978 if formation above the nahcolite bed is not to betreated. Packers, cement, or other sealing systems may be used toinhibit formation fluid past a lower portion of nahcolite bed 1978′ ifformation below the nahcolite bed is not to be treated and wellbores 428extend past the nahcolite bed.

After solution mining of nahcolite beds 1978, 1978′ is completed,heaters in heater wellbores 428 may raise the temperature of hydrocarboncontaining layer 484 to mobilization and/or pyrolysis temperatures.Formation fluid generated from hydrocarbon containing layer 484 may beproduced from the formation through converted solution mining wells1080. Initially, vaporized formation fluid may flow along heaterwellbores 428 to converted solution mining wells 1080 in nahcolite bed1978. Initially, liquid formation fluid may flow along heater wellbores428 to converted solution mining wells 1080 in nahcolite bed 1978′. Asheating is continued, fractures caused by heating and/or increasedpermeability due to the removal of material may provide additional fluidpathways to nahcolite beds 1978, 1978′ so that formation fluid generatedfrom hydrocarbon containing layer 484 may be produced from convertedsolution mining wells 1080 in the nahcolite beds. Converted solutionmining wells 1080 in nahcolite bed 1978 may be used to primarily producevaporized formation fluids. Converted solution mining wells 1080 innahcolite bed 1978′ may be used to primarily produce liquid formationfluid.

In some embodiments, the second fluid produced from the formation duringsolution mining is used to produce sodium bicarbonate. Sodiumbicarbonate may be used in the food and pharmaceutical industries, inleather tanning, in fire retardation, in wastewater treatment, and influe gas treatment (flue gas desulphurization and hydrogen chloridereduction). The second fluid may be kept pressurized and at an elevatedtemperature when removed from the formation. The second fluid may becooled in a crystallizer to precipitate sodium bicarbonate.

In some embodiments, the second fluid produced from the formation duringsolution mining is used to produce sodium carbonate, which is alsoreferred to as soda ash. Sodium carbonate may be used in the manufactureof glass, in the manufacture of detergents, in water purification,polymer production, tanning, paper manufacturing, effluentneutralization, metal refining, sugar extraction, and/or cementmanufacturing. The second fluid removed from the formation may be heatedin a treatment facility to form sodium carbonate (soda ash) and/orsodium carbonate brine. Heating sodium bicarbonate will form sodiumcarbonate according to the equation:2NaHCO₃→Na₂CO₃+CO₂+H₂O.  (EQN. 15)

In certain embodiments, the heat for heating the sodium bicarbonate isprovided using heat from the formation. For example, a heat exchangerthat uses steam produced from the water introduced into the hotformation may be used to heat the second fluid to dissociationtemperatures of the sodium bicarbonate. In some embodiments, the secondfluid is circulated through the formation to utilize heat in theformation for further reaction. Steam and/or hot water may also be addedto facilitate circulation. The second fluid may be circulated through aheated portion of the formation that has been subjected to the in situheat treatment process to produce hydrocarbons from the formation. Atleast a portion of the carbon dioxide generated during sodium carbonatedissociation may be adsorbed on carbon that remains in the formationafter the in situ heat treatment process. In some embodiments, thesecond fluid is circulated through conduits previously used to heat theformation.

In some embodiments, higher temperatures are used in the formation (forexample, above about 120° C., above about 130° C., above about 150° C.,or below about 250° C.) during solution mining of nahcolite. The firstfluid is introduced into the formation under pressure sufficient toinhibit sodium bicarbonate from dissociating to produce carbon dioxide.The pressure in the formation may be maintained at sufficiently highpressures to inhibit such nahcolite dissociation but below pressuresthat would result in fracturing the formation. In addition, the pressurein the formation may be maintained high enough to inhibit steamformation if hot water is being introduced in the formation. In someembodiments, a portion of the nahcolite may begin to decompose in situ.In such cases, nahcolite is removed from the formation as soda ash. Ifsoda ash is produced from solution mining of nahcolite, the soda ash maybe transported to a separate facility for treatment. The soda ash may betransported through a pipeline to the separate facility.

As described above, in certain embodiments, following removal ofnahcolite from the formation, the formation is treated using the in situheat treatment process to produce formation fluids from the formation.In some embodiments, the formation is treating using the in situ heattreatment process before solution mining nahcolite from the formation.The nahcolite may be converted to sodium carbonate (from sodiumbicarbonate) during the in situ heat treatment process. The sodiumcarbonate may be solution mined as described above for solution miningnahcolite prior to the in situ heat treatment process.

In some formations, dawsonite is present in the formation. Dawsonitewithin the heated portion of the formation decomposes during heating ofthe formation to pyrolysis temperature. Dawsonite typically decomposesat temperatures above 270° C. according to the reaction:2NaAl(OH)₂CO₃→Na₂CO₃+Al₂O₃+2H₂O+CO₂.  (EQN. 16)

Sodium carbonate may be removed from the formation by solution miningthe formation with water or other fluid into which sodium carbonate issoluble. In certain embodiments, alumina formed by dawsonitedecomposition is solution mined using a chelating agent. The chelatingagent may be injected through injection wells, production wells, and/orheater wells used for solution mining nahcolite and/or the in situ heattreatment process (for example, injection wells 788, production wells206, and/or heat sources 202 depicted in FIG. 293). The chelating agentmay be an aqueous acid. In certain embodiments, the chelating agent isEDTA (ethylenediaminetetraacetic acid). Other examples of possiblechelating agents include, but are not limited to, ethylenediamine,porphyrins, dimercaprol, nitrilotriacetic acid,diethylenetriaminepentaacetic acid, phosphoric acids, acetic acid,acetoxy benzoic acids, nicotinic acid, pyruvic acid, citric acid,tartaric acid, malonic acid, imidizole, ascorbic acid, phenols, hydroxyketones, sebacic acid, and boric acid. The mixture of chelating agentand alumina may be produced through production wells or other wells usedfor solution mining and/or the in situ heat treatment process (forexample, injection wells 788, production wells 206, and/or heat sources202, which are depicted in FIG. 293). The alumina may be separated fromthe chelating agent in a treatment facility. The recovered chelatingagent may be recirculated back to the formation to solution mine morealumina.

In some embodiments, alumina within the formation may be solution minedusing a basic fluid after the in situ heat treatment process. Basicfluids include, but are not limited to, sodium hydroxide, ammonia,magnesium hydroxide, magnesium carbonate, sodium carbonate, potassiumcarbonate, pyridine, and amines. In an embodiment, sodium carbonatebrine, such as 0.5 Normal Na₂CO₃, is used to solution mine alumina.Sodium carbonate brine may be obtained from solution mining nahcolitefrom the formation. Obtaining the basic fluid by solution mining thenahcolite may significantly reduce costs associated with obtaining thebasic fluid. The basic fluid may be injected into the formation througha heater well and/or an injection well. The basic fluid may combine withalumina to form an alumina solution that is removed from the formation.The alumina solution may be removed through a heater well, injectionwell, or production well.

Alumina may be extracted from the alumina solution in a treatmentfacility. In an embodiment, carbon dioxide is bubbled through thealumina solution to precipitate the alumina from the basic fluid. Carbondioxide may be obtained from dissociation of nahcolite, from the in situheat treatment process, or from decomposition of the dawsonite duringthe in situ heat treatment process.

In certain embodiments, a formation may include portions that aresignificantly rich in either nahcolite or dawsonite only. For example, aformation may contain significant amounts of nahcolite (for example, atleast about 20 weight %, at least about 30 weight %, or at least about40 weight %) in a depocenter of the formation. The depocenter maycontain only about 5 weight % or less dawsonite on average. However, inbottom layers of the formation, a weight percent of dawsonite may beabout 10 weight % or even as high as about 25 weight %. In suchformations, it may be advantageous to solution mine for nahcolite onlyin nahcolite-rich areas, such as the depocenter, and solution mine fordawsonite only in the dawsonite-rich areas, such as the bottom layers.This selective solution mining may significantly reduce fluid costs,heating costs, and/or equipment costs associated with operating thesolution mining process.

In certain formations, dawsonite composition varies between layers inthe formation. For example, some layers of the formation may havedawsonite and some layers may not. In certain embodiments, more heat isprovided to layers with more dawsonite than to layers with lessdawsonite. Tailoring heat input to provide more heat to certaindawsonite layers more uniformly heats the formation as the reaction todecompose dawsonite absorbs some of the heat intended for pyrolyzinghydrocarbons. FIG. 299 depicts an embodiment for heating a formationwith dawsonite in the formation. Hydrocarbon layer 484 may be cored toassess the dawsonite composition of the hydrocarbon layer. The mineralcomposition may be assessed using, for example, FTIR (Fourier transforminfrared spectroscopy) or x-ray diffraction. Assessing the corecomposition may also assess the nahcolite composition of the core. Afterassessing the dawsonite composition, heater 438 may be placed inwellbore 428. Heater 438 includes sections to provide more heat tohydrocarbon layers with more dawsonite in the layers (hydrocarbon layers484D). Hydrocarbon layers with less dawsonite (hydrocarbon layers 484C)are provided with less heat by heater 438. Heat output of heater 438 maybe tailored by, for example, adjusting the resistance of the heateralong the length of the heater. In one embodiment, heater 438 is atemperature limited heater, described herein, that has a highertemperature limit (for example, higher Curie temperature) in sectionsproximate layers 484D as compared to the temperature limit (Curietemperature) of sections proximate layers 484C. The resistance of heater438 may also be adjusted by altering the resistive conducting materialsalong the length of the heater to supply a higher energy input (wattsper meter) adjacent to dawsonite rich layers.

Solution mining dawsonite and nahcolite may be relatively simpleprocesses that produce alumina and soda ash from the formation. In someembodiments, hydrocarbons produced from the formation using the in situheat treatment process may be fuel for a power plant that producesdirect current (DC) electricity at or near the site of the in situ heattreatment process. The produced DC electricity may be used on the siteto produce aluminum metal from the alumina using the Hall process.Aluminum metal may be produced from the alumina by melting the aluminain a treatment facility on the site. Generating the DC electricity atthe site may save on costs associated with using hydrotreaters,pipelines, or other treatment facilities associated with transportingand/or treating hydrocarbons produced from the formation using the insitu heat treatment process.

In some embodiments, acid may be introduced into the formation throughselected wells to increase the porosity adjacent to the wells. Forexample, acid may be injected if the formation comprises limestone ordolomite. The acid used to treat the selected wells may be acid producedduring in situ heat treatment of a section of the formation (forexample, hydrochloric acid), or acid produced from byproducts of the insitu heat treatment process (for example, sulfuric acid produced fromhydrogen sulfide or sulfur).

In some embodiments, a saline rich zone is located at or near anunleached portion of the formation. The saline rich zone may be anaquifer in which water has leached out nahcolite and/or other minerals.A high flow rate may pass through the saline rich zone. Saline waterfrom the saline rich zone may be used to solution mine another portionof the formation. In certain embodiments, a steam and electricitycogeneration facility may be used to heat the saline water prior to usefor solution mining.

FIG. 300 depicts a representation of an embodiment for solution miningwith a steam and electricity cogeneration facility. Treatment area 1028may be formed in unleached portion 1092 of the formation (for example,an oil shale formation). Several treatment areas 1028 may be formed inunleached portion 1092 leaving top, side, and/or bottom walls ofunleached formation as barriers around the individual treatment areas toinhibit inflow and outflow of formation fluid during the in situ heattreatment process. The thickness of the walls surrounding the treatmentareas may be 10 m or more. For example, the side wall near closest tosaline zone 1100 may be 60 m or more thick, and the top wall may be 30 mor more thick.

Treatment area 1028 may have significant amounts of nahcolite. Salinezone 1100 is located at or near treatment area 1028. In certainembodiments, zone 1100 is located up dip from treatment area 1028. Zone1100 may be leached or partially leached such that the zone is mainlyfilled with saline water.

In certain embodiments, saline water is removed (pumped) from zone 1100using production well 206. Production well 206 may be located at or nearthe lowest portion of zone 1100 so that saline water flows into theproduction well. Saline water removed from zone 1100 is heated to hotwater and/or steam temperatures in facility 796. Facility 796 may burnhydrocarbons to run generators that produce electricity. Facility 796may burn gaseous and/or liquid hydrocarbons to make electricity. In someembodiments, pulverized coal is used to make electricity. Theelectricity generated may be used to provide electrical power forheaters or other electrical operations (for example, pumping). Wasteheat from the generators is used to make hot water and/or steam from thesaline water. After the in situ heat treatment process of one or moretreatment areas 1028 results in the production of hydrocarbons, at leasta portion of the produced hydrocarbons may be used as fuel for facility796.

The hot water and/or steam made by facility 796 is provided to solutionmining well 1080. Solution mining well 1080 is used to solution minetreatment area 1028. Nahcolite and/or other minerals are removed fromtreatment area 1028 by solution mining well 1080. The nahcolite may beremoved as a nahcolite solution from treatment area 1028. The solutionremoved from treatment area 1028 may be a brine solution with dissolvednahcolite. Heat from the removed nahcolite solution may be used infacility 796 to heat saline water from zone 1100 and/or other fluids.The nahcolite solution may then be injected through injection well 788into zone 1100. In some embodiments, injection well 788 injects thenahcolite solution into zone 1100 up dip from production well 206.Injection may occur a significant distance up dip so that nahcolitesolution may be continuously injected as saline water is removed fromthe zone without the two fluids substantially intermixing. In someembodiments, the nahcolite solution from treatment area 1028 is providedto injection well 788 without passing through facility 796 (thenahcolite solution bypasses the facility).

The nahcolite solution injected into zone 1100 may be left in the zonepermanently or for an extended period of time (for example, aftersolution mining, production well 206 may be shut in). In someembodiments, the nahcolite stored in zone 1100 is accessed at latertimes. The nahcolite may be produced by removing saline water from zone1100 and processing the saline water to make sodium bicarbonate and/orsoda ash.

Solution mining using saline water from zone 1100 and heat from facility796 to heat the saline water may be a high efficiency process forsolution mining treatment area 1028. Facility 796 is efficient atproviding heat to the saline water. Using the saline water to solutionmine decreases costs associated with pumping and/or transporting waterto the treatment site. Additionally, solution mining treatment area 1028preheats the treatment area for any subsequent heat treatment of thetreatment area, enriches the hydrocarbon content in the treatment areaby removing nahcolite, and/or creates more permeability in the treatmentarea by removing nahcolite.

In certain embodiments, treatment area 1028 is further treated using anin situ heat treatment process following solution mining of thetreatment area. A portion of the electricity generated in facility 796may be used to power heaters for the in situ heat treatment process.

In some embodiments, a perimeter barrier may be formed around theportion of the formation to be treated. The perimeter barrier mayinhibit migration of formation fluid into or out of the treatment area.The perimeter barrier may be a frozen barrier and/or a grout barrier.After formation of the perimeter barrier, the treatment area may beprocessed to produce desired products.

Formations that include non-hydrocarbon materials may be treated toremove and/or dissolve a portion of the non-hydrocarbon materials from asection of the formation before hydrocarbons are produced from thesection. In some embodiments, the non-hydrocarbon materials are removedby solution mining. Removing a portion of the non-hydrocarbon materialsmay reduce the carbon dioxide generation sources present in theformation. Removing a portion of the non-hydrocarbon materials mayincrease the porosity and/or permeability of the section of theformation. Removing a portion of the non-hydrocarbon materials mayresult in a raised temperature in the section of the formation.

After solution mining, some of the wells in the treatment may beconverted to heater wells, injection wells, and/or production wells. Insome embodiments, additional wells are formed in the treatment area. Thewells may be heater wells, injection wells, and/or production wells.Logging techniques may be employed to assess the physicalcharacteristics, including any vertical shifting resulting from thesolution mining, and/or the composition of material in the formation.Packing, baffles or other techniques may be used to inhibit formationfluid from entering the heater wells. The heater wells may be activatedto heat the formation to a temperature sufficient to support combustion.

One or more production wells may be positioned in permeable sections ofthe treatment area. Production wells may be horizontally and/orvertically oriented. For example, production wells may be positioned inareas of the formation that have a permeability of greater than 5 darcyor 10 darcy. In some embodiments, production wells may be positionednear a perimeter barrier. A production well may allow water andproduction fluids to be removed from the formation. Positioning theproduction well near a perimeter barrier enhances the flow of fluidsfrom the warmer zones of the formation to the cooler zones.

FIG. 301 depicts an embodiment of a process for treating a hydrocarboncontaining formation with a combustion front. Barrier 1058 (for example,a frozen barrier or a grout barrier) may be formed around a perimeter oftreatment area 1028 of the formation. The footprint defined by thebarrier may have any desired shape such as circular, square,rectangular, polygonal, or irregular shape. Barrier 1058 may be formedusing one or more barrier wells 200. The barrier may be any barrierformed to inhibit the flow of fluid into or out of treatment area 1028.In some embodiments, barrier 1058 may be a double barrier.

Heat may be provided to treatment area 1028 through heaters positionedin injection wells 788. In some embodiments, the heaters in injectionwells 788 heat formation adjacent to the injections wells totemperatures sufficient to support combustion. Heaters in injectionwells 788 may raise the formation near the injection wells totemperatures from about 90° C. to about 120° C. or higher (for example,a temperature of about 90° C., 95° C., 100° C., 110° C., or 120° C.).

Injection wells 788 may be used to introduce a combustion fuel, anoxidant, steam and/or a heat transfer fluid into treatment area 1028,either before, during, or after heat is provided to treatment area 1028from heaters. In some embodiments, injection wells 788 are incommunication with each other to allow the introduced fluid to flow fromone well to another. Injection wells 788 may be located at positionsthat are relatively far away from perimeter barrier 1058. Introducedfluid may cause combustion of hydrocarbons in treatment area 1028. Heatfrom the combustion may heat treatment area 1028 and mobilize fluidstoward production wells 206.

A temperature of treatment area 1028 may be monitored using temperaturemeasurement devices placed in monitoring wells and/or temperaturemeasurement devices in injection wells 788, production wells 206, and/orheater wells.

In some embodiments, a controlled amount of oxidant (for example, airand/or oxygen) is provided in injection wells 788 to advance a heatfront towards production wells 206. In some embodiments, the controlledamount of oxidant is introduced into the formation after solution mininghas established permeable interconnectivity between at least twoinjection wells. The amount of oxidant is controlled to limit theadvancement rate of the heat front and to limit the temperature of theheat front. The advancing heat front may pyrolyze hydrocarbons. The highpermeability in the formation allows the pyrolyzed hydrocarbons tospread in the formation towards production wells without being overtakenby the advancing heat front.

Vaporized formation fluid and/or gas formed during the combustionprocess may be removed through gas wells 1102 and/or injection wells788. Venting of gases through gas wells 1102 and/or injection wells 788may force the combustion front in a desired direction.

In some embodiments, the formation may be heated to a temperaturesufficient to cause pyrolysis of the formation fluid by the steam and/orheat transfer fluid. The steam and/or heat transfer fluid may be heatedto temperatures of about 300° C., about 400° C., about 500° C., or about600° C. In certain embodiments, the steam and/or heat transfer fluid maybe co-injected with the fuel and/or oxidant.

FIG. 302 depicts a representation of a cross-sectional view of anembodiment for treating a hydrocarbon containing formation with acombustion front. As the combustion front is initiated and/or fueledthrough injection wells 788, formation fluid near periphery 1104 of thecombustion front becomes mobile and flow towards production wells 206located proximate barrier 1058. Injection wells may include smart welltechnology. Combustion products and noncondensable formation fluid maybe removed from the formation through gas wells 1102. In someembodiments, no gas wells are formed in the formation. In suchembodiments, formation fluid, combustion products and noncondensableformation fluid are produced through production wells 206. Inembodiments that include gas wells 1102, condensable formation fluid maybe produced through production well 206. In some embodiments, productionwell 206 is located below injection well 788. Production well 206 may beabout 1 m, 5 m, 10 m or more below injection well 788. Production wellmay be a horizontal well. Periphery 1104 of the combustion front mayadvance from the toe of production well 206 towards the heel of theproduction well. Production well 206 may include a perforated liner thatallows hydrocarbons to flow into the production well. In someembodiments, a catalyst may be placed in production well 206. Thecatalyst may upgrade and/or stabilize formation fluid in the productionwell.

Gases may be produced during in situ heat treatment processes and duringmany conventional production processes. Some of the produced gases (forexample, carbon dioxide and/or hydrogen sulfide) when introduced intowater may change the pH of the water to less than 7. Such gases aretypically referred to as sour gas or acidic gas. Introducing sour gasfrom produced fluid into subsurface formations may reduce or eliminatethe need for or size of certain surface facilities (for example, a Clausplant or Scot gas treater). Introducing sour gas from produced formationfluid into subsurface formations may make the formation fluid moreacceptable for transportation, use, and/or processing. Removal of sourgas having a low heating value (for example, carbon dioxide) fromformation fluids may increase the caloric value of the gas streamseparated from the formation fluid.

Net release of sour gas to the atmosphere and/or conversion of sour gasto other compounds may be reduced by utilizing the produced sour gasand/or by storing the sour gas within subsurface formations. In someembodiments, the sour gas is stored in deep saline aquifers. Deep salineaquifers may be at depths of about 900 m or more below the surface. Thedeep saline aquifers may be relatively thick and permeable. A thick andrelatively impermeable formation strata may be located over deep salineaquifers. For example, 500 m or more of shale may be located above thedeep saline aquifer. The water in the deep saline aquifer may beunusable for agricultural or other common uses because of the highmineral content in the water. Over time, the minerals in the water mayreact with introduced sour gas to form precipitates in the deep salineaquifer. The deep saline aquifer used to store sour gas may be below thetreatment area, at another location in the same formation, or in anotherformation. If the deep saline aquifer is located at another location inthe same formation or in another formation, the sour gas may betransported to the deep saline aquifer by pipeline.

In some embodiments, injection wells used to inject sour gas may bevertical, slanted, and/or directionally steered wells with a significanthorizontal or near horizontal portion. The horizontal or near horizontalportion of the injection well may be located near or at the bottom ofthe deep saline aquifer. FIG. 303 depicts a representation of anembodiment of a system for injection of sour gases produced from the insitu heat treatment process into the deep saline aquifer. Formationfluids may be produced from hydrocarbon layer 484. In certainembodiments, formation fluids are produced using an in situ heattreatment process through production well 206. The sour gas (forexample, gas including at least carbon dioxide and hydrogen sulfide) maybe separated from the formation fluids in gas/liquid separator 1106using known gas/liquid separation techniques.

The separated sour gas may be transported to formation 1108 via conduit1110 (for example, a pipeline). Formation 1108 may include aquifer 1112(for example, a deep saline aquifer) and barrier portion 1114 (forexample, shale). The sour gas may be injected into deep saline aquifer1112 through injection well 1116. Injection well 1116 may have verticalportion 1118 and horizontal portion 1120. Horizontal portion 1120 may benear or at the bottom of deep saline aquifer 1112. The sour gas may beless dense than formation fluid in the deep saline aquifer. The sour gasmay diffuse upwards in the aquifer towards barrier layer 1114.Horizontal portion 1120 may allow injection of the sour gas in a largeportion of deep saline aquifer 1112. Openings in horizontal portion 1120may be critical flow orifices so that fluid is introduced substantiallyequally along the length of the horizontal portion.

Cement 1122 may be used to seal conduit 1110 in formation. Cement 1122used in injection wellbores to form seals at the surface and/or at aninterface of deep saline aquifer with barrier layer 1114 may be selectedso that the cement does not degrade due to the temperature, pressure andchemical environment due to exposure to sour gas.

The deep saline aquifer or aquifers used to store sour gas may be atsufficient depth such that the carbon dioxide in the sour gas isintroduced in the formation in a supercritical state. Supercriticalcarbon dioxide injection may maximize the density of the fluidintroduced into the formation. The depths of outlets of injection wellsused to introduce acidic gases in the formation may be 900 m or morebelow the surface.

Injection of sour gas into a non-producing formation and/or using sourgas as flooding agents are described in U.S. Pat. Nos. 7,128,150 toThomas et al.; RE 39,244 to Eaton; RE 39,077 to Eaton; 6,755,251 toThomas et al.; 6,283,230 to Peters, all of which are incorporated byreference as if fully set forth herein.

During production of formation fluids from a subsurface formation,acidic gases may react with water in the formation and produce acids.For example, carbonic acid may be produced from the reaction of carbondioxide with water during heating of the formation. Portions of wellsmade of certain materials, such as carbon steel, may start todeteriorate or corrode in the presence of the produced acids. To inhibitcorrosion due to produced acids (for example, carbonic acid), fluidsand/or polymers (for example, corrosion inhibitors, foaming agents,surfactants, basic fluids, hydrocarbons, high density polyethylene, ormixtures thereof) may be introduced in the wellbore to neutralize,dissolve the acids, and/or inhibit corrosion of piping in the formation.

In some embodiments, hydrogen sulfide and/or carbon dioxide areseparated from the produced gases and introduced into one or morewellbores in a subsurface formation. Water present in the gas introducedinto the formation may interact with hydrogen sulfide to form a sulfidelayer on metal surfaces of the injection well. Formation of the sulfidelayer may inhibit further corrosion of the metal surfaces of theinjection well by carbonic acid and/or other acids. The formation of thesulfide layer may allow for the use of carbon steel or other relativelyinexpensive alloys during the introduction of sour gas into subsurfaceformations.

In certain embodiments, a temperature measurement tool assesses theactive impedance of an energized heater. The temperature measurementtool may utilize the frequency domain analysis algorithm associated withPartial Discharge measurement technology (PD) coupled with timed domainreflectometer measurement technology (TDR). A set of frequency domainanalysis tools may be applied to a TDR signature. This process mayprovide unique information in the analysis of the energized heater suchas, but not limited to, an impedance log of the entire length of theheater per unit length. The temperature measurement tool may providecertain advantages for assessing the temperature of a downhole heater.

In certain embodiments, the temperature measurement tool assesses theimpedance per unit length and gives a profile on the entire length ofthe heated section of the heater. The impedance profile may be used inassociation with laboratory data for the heater (such as temperature andresistance profiles for heaters measured at various loads andfrequencies) to assess the temperature per unit length of the heatedsection. The impedance profile may also be used to assess variouscomputer models for heaters that are used in association with thereservoir simulations.

In certain embodiments, the temperature measurement tool assesses anaccurate impedance profile of a heater in a specific formation after anumber of heater wells have been installed and energized in the specificformation. The accurate impedance profile may assess the actual reactiveand real power consumption for each heater that is used similarly. Thisinformation may be used to properly size surface electrical distributionequipment and/or eliminate any extra capacity designed to accommodateany anticipated heater impedance turndown ratio or any unknown powerfactor or reactive power consumption for the heaters.

In certain embodiments, the temperature measurement tool is used totroubleshoot malfunctioning heaters and assess the impedance profile ofthe length of the heated section. The impedance profile may be able toaccurately predict the location of a faulted section and its relativeimpedance to ground. This information may be used to accurately assessthe appropriate reduction in surface voltage to allow the heater tocontinue to operate in a limited capacity. This method may be morepreferable than abandoning the heater in the formation.

In certain embodiments, frequency domain PD testing offers an improvedset of PD characterization tools. A basic set of frequency domain PDtesting tools are described in “The Case for Frequency Domain PD TestingIn The Context Of Distribution Cable”, Steven Boggs, ElectricalInsulation Magazine, IEEE, Vol. 19, Issue 4, July-August 2003, pages13-19, which is incorporated by reference as if fully set forth herein.Frequency domain PD detection sensitivity under field conditions may beone to two orders of magnitude greater than for time domain testing as aresult of there not being a need to trigger on the first PD pulse abovethe broadband noise, and the filtering effect of the cable between thePD detection site and the terminations. As a result of this greatlyincreased sensitivity and the set of characterization tools, frequencydomain PD testing has been developed into a highly sensitive andreliable tool for characterizing the condition of distribution cableduring normal operation while the cable is energized.

During or after solution mining and/or the in situ heat treatmentprocess, some existing cased heater wells and/or some existing casedmonitor wells may be converted into production wells and/or injectionwells. Existing cased wells may be converted to production and/orinjection wells by perforating a portion of the well casing withperforation devices that utilize explosives. Also, some production wellsmay be perforated at one or more cased locations to facilitate removalof formation fluid through newly opened sections in the productionwells. In some embodiments, perforation devices may be used in openwellbores to fracture formation adjacent to the wellbore.

In some embodiments, pre-perforated portions of wells are installed.Coverings may initially be placed over the perforations. At a desiredtime, the covering of the perforations may be removed to open additionalportions of the wells or to convert the wells to production wells and/orinjections wells. Knowing which wells will need to be converted toproduction wells and/or injection wells may not be apparent at the timeof well installation. Using pre-perforated wells for all wells may beprohibitively expensive.

Perforation devices may be used to form openings in a well. Perforationdevices may be obtained from, for example, Schlumberger USA (Sugar Land,Tex., USA). Perforation devices may include, but are not limited to,capsule guns and/or hollow carrier guns. Perforation devices may useexplosives to form openings in a well. The well may need to be at arelatively cool temperature to inhibit premature detonation of theexplosives. Temperature exposure limits of some explosives commonly usedfor perforation devices are a maximum exposure of 1 hour to atemperature of about 260° C., and a maximum exposure of 10 hours to atemperature of about 210° C. In some embodiments, the well is cooledbefore use of the perforation device. In some embodiments, theperforation device is insulated to inhibit heat transfer to theperforation device. The use of insulation may not be suitable for wellswith portions that are at high temperature (for example, above 300° C.).

In some embodiments, the perforation device is equipped with acirculated fluid cooling system. The circulated fluid cooling system maykeep the temperature of the perforation device below a desired value.Keeping the temperature of the perforation device below a selectedtemperature may inhibit premature detonation of explosives in theperforation device.

One or more temperature sensing devices may be included in thecirculated fluid cooling system to allow temperatures in the well and/ornear the perforating device to be observed. After insertion into thewell, the perforation device may be activated to form openings in thewell. The openings may be of sufficient size to allow fluid to be pumpedthrough the well after removal of the perforation device positioningapparatus.

FIG. 304 represents a perspective view of circulated fluid coolingsystem 1124 that provides continuous and/or semi-continuous coolingfluid to perforating device 1126. Circulated fluid cooling system 1124may include outer tubing 1128, inner tubing 1130, connectors 1132,sleeve 1134, support 1136, perforating device 1126, temperature sensor1138, and control cable 1140.

Sleeve 1134 may be coupled to outer tubing 1128 by connector 1132. Insome embodiments, outer tubing 1128 is a coiled tubing string, andconnector 1132 is a threaded connection. Sleeve 1134 may be a thinwalled sleeve. In some embodiments, sleeve 1134 is made of a polymer.Sleeve 1134 may have minimal thickness to maximize explosive performanceof perforation device 1126, yet still be sufficiently strong to supportthe forces applied to the sleeve by the hydrostatic column andcirculation of cooling fluid.

Inner tubing 1130 may be positioned inside of outer tubing 1128. In someembodiments, inner tubing 1130 is a coiled tubing string. Support 1136may be coupled to inner tubing by connector 1132. In some embodiments,support 1136 is a pipe and connector 1132 is a threaded connection.Perforation device 1126 may be secured to the outside of support 1136. Anumber of perforation devices may be secured to the outside of thesupport in series. Using a number of perforation devices may allow along length of perforations to be formed in the well on a single trip ofcirculated fluid cooling system 1124 into the well.

Temperature sensor 1138 and control cable 1140 may be positioned throughinner tubing 1130 and support 1136. Temperature sensor 1138 may be afiber optic cable or plurality of thermocouples that are capable ofsensing temperature at various locations in circulated fluid coolingsystem 1124. Control cable 1140 may be coupled to perforation device1126. A signal may be sent through control cable to detonate explosivesin perforation device 1126.

Cooling fluid 1142 may flow downwards through inner tubing 1130 andsupport 1136 and return to the surface past perforation device 1126 inthe space between the support and sleeve 1134 and in the space betweenthe inner tubing and outer tubing 1128. Cooling fluid 1142 may be water,glycol, or any other suitable heat transfer fluid.

In some embodiments, a long length of support 1136 and sleeve 1134 maybe left below perforation device 1126 as a dummy section. Temperaturemeasurements taken by temperature sensor 1138 in the dummy section maybe used to monitor the temperature rise of the leading portion ofcirculated fluid cooling system 1124 as the circulated fluid coolingsystem is introduced into the well. The dummy section may also be atemperature buffer for perforation device 1126 that inhibits rapidtemperature rise in the perforation device. In other embodiments, thecirculated fluid cooling system may be introduced into the well withoutperforation devices to determine that the temperature increase theperforation device will be exposed to will be known before theperforation device is placed in the well.

To use circulated fluid cooling system 1124, the circulated fluidcooling system is lowered into the well. Cooling fluid 1142 keeps thetemperature of perforation device 1126 below temperatures that mayresult in the premature detonation of explosives of the perforationdevice. After the perforation device is positioned at the desiredlocation in the well, circulation of cooling fluid 1142 is stopped. Insome embodiments, cooling fluid 1142 is removed from circulated fluidcooling system 1124. Then, control cable 1140 may be used to detonatethe explosives of perforation device 1126 to form openings in the well.Outer tubing 1128 and inner tubing 1130 may be removed from the well,and the remaining portions of sleeve 1134 and/or support 1136 may bedisconnected from the outer tubing and the inner tubing.

To perforate another well, a new perforation device may be secured tothe support if the support is reusable. The support may be coupled toinner tubing, and a new sleeve may be coupled to the outer tubing. Thenewly reformed circulated fluid cooling system 1124 may be deployed inthe well to be perforated.

Heating a formation with heat sources having electrically conductingmaterial may increase permeability in the formation and/or lowerviscosity of hydrocarbons in the formation. Heat sources withelectrically conducting material may allow current to flow through theformation from one heat source to another heat source. Heating usingcurrent flow or “joule heating” through the formation may heat portionsof the hydrocarbon layer in a shorter amount of time relative to heatingthe hydrocarbon layer using conductive heating between heaters spacedapart in the formation.

In certain embodiments, subsurface formations (for example, tar sands orheavy hydrocarbon formations) include dielectric media. Dielectric mediamay exhibit conductivity, relative dielectric constant, and losstangents at temperatures below 100° C. Loss of conductivity, relativedielectric constant, and dissipation factor may occur as the formationis heated to temperatures above 100° C. due to the loss of moisturecontained in the interstitial spaces in the rock matrix of theformation. To prevent loss of moisture, formations may be heated attemperatures and pressures that minimize vaporization of water. In someembodiments, conductive solutions are added to the formation to helpmaintain the electrical properties of the formation. Heating a formationat low temperatures may require the hydrocarbon layer to be heated forlong periods of time to produce permeability and/or injectivity.

In some embodiments, formations are heated using joule heating totemperatures and pressures that vaporize the water and/or conductivesolutions. Material used to produce the current flow, however, maybecome damaged due to heat stress and/or loss of conductive solutionsmay limit heat transfer in the layer. In addition, when using currentflow or joule heating, magnetic fields may form. Due to the presence ofmagnetic fields, non-ferromagnetic materials may be desired foroverburden casings. Although many methods have been described forheating formations using joule heating, efficient and economic methodsof heating and producing hydrocarbons using heat sources withelectrically conductive material are needed.

In some embodiments, heat sources that include electrically conductivematerials are positioned in a hydrocarbon layer. Portions of thehydrocarbon layer may be heated from current generated from the heatsources that flows from the heat sources and through the layer.Positioning of electrically conductive heat sources in a hydrocarbonlayer at depths sufficient to minimize loss of conductive solutions mayallow hydrocarbons layers to be heated at relatively high temperaturesover a period of time with minimal loss of water and/or conductivesolutions.

FIGS. 305-309 depict schematics of embodiments for treating a subsurfaceformation using heat sources having electrically conductive material.FIG. 305 depicts first conduit 1980 and second conduit 1982 positionedin wellbores 428 in hydrocarbon layer 484. In certain embodiments, firstconduit 1980 and/or second conduit 1982 are conductors (for example,exposed metal or bare metal conductors). In some embodiments, conduits1980, 1982 are oriented substantially horizontally or at an incline inthe formation. In some embodiments, conduits 1980, 1982 areperpendicular to the geological structure to inhibit channels fromforming in the rock matrix during heating. Conduits 1980, 1982 may bepositioned in a bottom portion of hydrocarbon layer 484.

Wellbores 428 may be open wellbores. In some embodiments, the conduitsextend from a portion of the wellbore. In some embodiments, verticalportions of wellbores 428 are cemented with non-conductive cement orfoam cement. Wellbores 428 may include packers 1086 and/or electricalinsulators 2016. In some embodiments, packers 1086 are not necessary.Electrical insulators 2016 may insulate conduits 1980, 1982 from casing564.

In some embodiments, the portion of casing 564 adjacent to overburden482 is made of material that inhibits ferromagnetic effects. The casingin the overburden may be made of fiberglass, polymers, and/or anon-ferromagnetic metal (for example, a high manganese steel).Inhibiting ferromagnetic effects in the portion of casing 564 adjacentto overburden 482 may reduce heat losses to the overburden and/orelectrical losses in the overburden. In some embodiments, overburdencasings 564 include non-metallic materials such as fiberglass,polyvinylchloride (PVC), chlorinated polyvinylchloride (CPVC),high-density polyethylene (HDPE), and/or non-ferromagnetic metals (forexample, non-ferromagnetic high manganese steels). HDPEs with workingtemperatures in a range for use in overburden 482 include HDPEsavailable from Dow Chemical Co., Inc. In some embodiments, casing 564includes carbon steel coupled on the inside and/or outside diameter of anon-ferromagnetic metal (for example, carbon steel clad with copper oraluminum) to inhibit ferromagnetic effects or inductive effects in thecarbon steel. Other non-ferromagnetic metals include, but are notlimited to, manganese steels with at least 15% by weight manganese, 0.7%by weight carbon, 2% by weight chromium, iron aluminum alloys with atleast 18% by weight aluminum, and austenitic stainless steels such as304 stainless steel or 316 stainless steel.

Portions or all of conduits 1980, 1982 may include electricallyconductive material 1984. Electrically conductive materials include, butare not limited to, thick walled copper, heat treated copper (“hardenedcopper”), carbon steel clad with copper, aluminum or aluminum or copperclad with stainless steel 32. Conduits 1980, 1982 may have dimensionsand characteristics that enable the conduits to be used later asinjection wells and/or production wells. Conduit 1980 and/or conduit1982 may include perforations or openings 1988 to allow fluid to flowinto or out of the conduits. In some embodiments, portions of conduit1980 and/or conduit 1982 are pre-perforated. Coverings may initially beplaced over the perforations and removed later. In some embodiments,conduit 1980 and/or conduit 1982 include slotted liners. After a desiredtime (for example, after injectivity has been established in the layer),the coverings of the perforations may be removed or slots may be openedto open portions of conduit 1980 and/or conduit 1982 to convert theconduits to product wells and/or injection wells. In some embodiments,coverings are removed by inserting an expandable mandrel in the conduitsto remove coverings and/or open slots. In some embodiments, heat is usedto degrade material placed in the openings in conduit 1980 and/orconduit 1982. After degradation, fluid may flow into or out of conduit1980 and/or conduit 1982.

Power to electrically conductive material 1984 may be supplied from oneor more surface power supplies through conductors 2000, 2000′.Conductors 2000, 2000′ may be cables supported on a tubular or othersupport member. In some embodiments, conductors 2000, 2000′ are 2000 areconduits through which electricity flows to conduit 1980 or conduit1982. Electrical connectors 2002 may be used to electrically coupleconductors 2000, 2000′ to conduits 1980, 1982. Conductor 2000electrically coupled to conduit 1980 and conductors 2000′ electricallycoupled to conduit 1982 may be coupled to the same power supply to forman electrical circuit.

In some embodiments, a direct current power source is supplied to eitherfirst conduit 1980 or second conduit 1982. In some embodiments, timevarying current is supplied to first conduit 1980 and second conduit1982. Current flowing from conductor 2000, 2000′ to conduits 1980, 1982may be low frequency current (for example, about 50 Hz, about 60 Hz, orup to about 1000 Hz). A voltage differential between the first conduit1980 and second conduit 1982 may range from about 100 volts to about1200 volts, from about 200 volts to about 1000 volts, or from about 500volts to 700 volts. In some embodiments, higher frequency current and/orhigher voltage differentials may be utilized. Use of time varyingcurrent may allow longer conduits to be positioned in the formation. Useof longer conduits allows more of the formation to be heated at one timeand may decrease overall operating expenses. Current flowing to firstconduit 1980 may flow through hydrocarbon layer 484 to second conduit1982, and back to the power supply. Flow of current through hydrocarbonlayer 484 may cause resistance heating of the hydrocarbon layer.

During the heating process, current flow in conduits 1980, 1982 may bemeasured at the surface. Measuring of the current entering conduits1980, 1982 may be used to monitor the progress of the heating process.Current between conduits 1980, 1982 may increase steadily untilvaporization of water occurs at the conduits, at which time a drop incurrent is observed. Current flow of the system is indicated by arrows2020. Current flow in hydrocarbon containing layer 484 between conduits1980, 1982 heats the hydrocarbon layer between and around the conduits.Conduits 1980, 1982 may be part of a pattern of conduits in theformation that provide multiple pathways between wells so that a largeportion of layer 484 may be heated. The pattern may be a regularpattern, (for example, a triangular or rectangular pattern) or anirregular pattern.

FIG. 306 depicts a schematic of an embodiment of a system for treating asubsurface formation using electrically conductive material. Conduit2022 and ground 1990 may extend from wellbores 428 into hydrocarbonlayer 484. Ground 1990 may be a rod or conduit positioned in hydrocarbonlayer 484 about 10 meters, about 15 meters, or about 20 meters away fromconduit 2022. In some embodiments, electrical insulators 2016electrically isolate ground 1990 from casing 564 and/or conduit 2018positioned in wellbore 428. If ground 1990 is a conduit, the ground mayinclude openings 1988.

Conduit 2022 may include sections 1992, 1994 of conductive material1984. Sections 1992, 1994 may be separated by electrically insulatingmaterial 1996. Electrically insulating material 1996 may includepolymers and/or one or more ceramic isolators. Section 1992 may beelectrically coupled to the power supply by conductor 2000. Section 1994may be electrically coupled to the power supply by conductor 2000′.Electrical insulators 2016 may separate conductor 2000 from conductor2000′. Electrically insulating material 1996 may have dimensions andinsulating properties sufficient to inhibit current from section 1992flowing across insulation material 1996 to section 1994. For example, alength of electrically insulating material may be about 30 meters, about35 meters, about 40 meters, or greater. Using a conduit that haselectrically conductive sections 1992, 1994 may allow fewer wellbores tobe drilled in the formation. Conduits having electrically conductivesections (“segmented heat sources”) may allow longer conduit lengthsand/or closer spacing.

Current provided through conductor 2000 may flow to conductive section1992 through hydrocarbon layer 484 to ground 1990. The electricalcurrent may flow along ground 1990 to a section of the ground adjacentto section 1994. The current may flow through hydrocarbon layer 484 tosection 1994 and through conductor 2000′ back to the power circuit tocomplete the electrical circuit. Electrical connector 2012 mayelectrically couple section 1994 to conductor 2000′. Current flow isindicated by arrows 2020. Current flow through hydrocarbon layer 484 mayheat the hydrocarbon layer to create fluid injectivity in the layer,mobilize hydrocarbons in the layer, and/or pyrolyze hydrocarbons in thelayer. When using segmented heat sources, the amount of current requiredfor the initial heating of the hydrocarbon layer may be at least 50%less than current required for heating using two non-segmented heatsources or two electrodes. Hydrocarbons may be produced from hydrocarbonlayer 484 and/or other sections of the formation using production wells.In some embodiments, one or more portions of conduit 1980 is positionedin a shale layer and ground 1990 is be positioned in hydrocarbon layer484. Current flow through conductors 2000, 2000′ in opposite directionsmay allow for cancellation of at least a portion of the magnetic fieldsdue to the current flow. Cancellation of at least a portion of themagnetic fields may inhibit induction effects in the overburden portionof conduit 1980 and the wellhead of the well.

FIG. 307 depicts an embodiment where first conduit 2022 and secondconduit 2022′ are used for heating hydrocarbon layer 484. Electricallyinsulating material 1996 may separate sections 1992, 1994 of firstconduit 2022. Electrically insulating material 1996 may separatesections 1992′, 1994′ of second conduit 2022′.

Current may flow from a power source through conductor 2000 of firstconduit 2022 to section 1992. The current may flow through hydrocarboncontaining layer 484 to section 1994′ of first conduit 2022. The currentmay return to the power source through conductor 2000′ of second conduit2022′. Similarly, current may flow through conductor 2000 of secondconductor 2022′ to section 1992′, through hydrocarbon layer 484 tosection 1994 of first conduit 2022, and the current may return to thepower source through conductor 2000′ of the first conduit 2022. Currentflow is indicated by the arrows. Generation of current flow fromelectrically conductive sections of conduits 2022, 2022′ may heatportions of hydrocarbon layer 484 between the conduits and create fluidinjectivity in the layer, mobilize hydrocarbons in the layer, and/orpyrolyze hydrocarbons in the layer. In some embodiments, one or moreportions of conduits 2022, 2022′ are positioned in shale layers.

By creating opposite current flow through the wellbore, as describedwith reference to FIG. 306 and FIG. 307, magnetic fields in theoverburden may cancel out. Cancellation of the magnetic fields in theoverburden may allow ferromagnetic materials be used in overburdencasings. Using ferromagnetic casings in the wellbores may be lessexpensive and/or easier to install than non-ferromagnetic casings (suchas fiberglass casings).

In some embodiments, two or more conduits may branch from a commonwellbore. FIG. 308 depicts a schematic of an embodiment of two conduitsextending from one common wellbore. Extending the conduits from onecommon wellbore may reduce costs by forming fewer wellbores. Fewerwellbores may be drilled further apart and produce the same heatingefficiencies and the same heating times as drilling two differentwellbores for each conduit through the formation. Extending conduitsfrom one common wellbore may allow longer conduit lengths and closerspacings to be used.

Conduits 1980, 1982 may extend from common portion 2004 of wellbore 428.Conduits 1980, 1982 may include electrically conductive material 1984.In some embodiments, conduits 1980, 1982 include electrically conductivesections and electrically insulating material, as described in FIGS. 307and 308. Conduits 1980 and/or conduit 1982 may include openings 1988.Current may flow from a power source to conduit 1980 through conductor2000. The current may pass through hydrocarbon containing layer 484 toconduit 1982. The current may pass from conduit 1982 through conductor2000′ back to the power source to complete the circuit. The flow ofcurrent as shown by the arrows through hydrocarbon layer 484 fromconduits 1980, 1982 heats the hydrocarbon layer between the conduits.

In some embodiments, a subsurface formation is heated using heatingsystems described in FIGS. 305, 306, 307, and/or 308. Fluids inhydrocarbon layer 484 may be heated to mobilization, visbreaking, and/orpyrolyzation temperatures. Such fluids may be produced from thehydrocarbon layer and/or from other sections of the formation. As thehydrocarbon layer 484 is heated, the conductivity of the heated portionof the hydrocarbon layer will increase. As the conductivity increases,heating in those portions may be concentrated. Conductivity ofhydrocarbon layers closer to the surface may increase by as much as afactor of three when the temperature of the deposit increases from 20°C. to 100° C. For deeper deposits, where the water vaporizationtemperature is higher due to increased fluid pressure, the increase inconductivity may be greater. Higher conductivity may increase theheating rate. As a result of heating, the viscosity of heavyhydrocarbons in the hydrocarbon layer are reduced. Reducing theviscosity may creating more injectivity in the layer and/or mobilizehydrocarbons in the layer. As a result of being able to rapidly heat thehydrocarbon layer, injectivity in the hydrocarbon layer may be completedin about two years. In some embodiments, the heating systems are used tocreate drainage paths between the heaters and production wells for thedrive and/or mobilization process. In some embodiments, the heatingsystems are used to provide heat during the drive process. The amount ofheat provided by the heating systems may be small compared to the heatinput from the drive process (for example, the heat input from steaminjection).

Once fluid injectivity has been established, a drive fluid, a pressuringfluid, and/or a solvation fluid may be injected in the heated portion ofhydrocarbon layer 484. Conduit 1982 may be perforated and fluid injectedthrough the conduit to mobilize and/or further heat hydrocarbon layer484. Fluids may drain and/or be mobilized toward conduit 1980. Conduit1980 may be perforated at the same time as conduit 1982 or perforated atthe start of production. Formation fluids may be produced throughconduit 1980 and/or other sections of the formation.

As shown in FIGS. 309, conduit 1980 is positioned in layer 1986 locatedbetween hydrocarbon layers 484A and 484B. Layer 1986 may be a shalelayer. Conduits 1980 may be any of the conduits described in FIGS. 305,306, 307, and/or 308. In some embodiments, portions of conduit 1980 arepositioned in hydrocarbon layers 484A or 484B and in layer 1986.

Layer 1986 may be a conductive layer, water/sand layer, or hydrocarbonslayer that has different porosity than hydrocarbon layer 484A and/orhydrocarbon layer 484B. Layer 1986 may have conductivities ranging fromabout 0.2 to about 0.5 mho/m. Hydrocarbon layers 484A and/or 484B mayhave conductivities ranging from about 0.02 to about 0.05 mho/m.Conductivity ratios between layer 1986 and hydrocarbon layers 484Aand/or 484B may range from about 10:1, about 20:1, or about 100:1. Whenlayer 1986 is a shale layer, heating the layer may desiccate the shalelayer and increase the permeability of the shale layer to allow fluid toflow through the shale layer. The increased permeability in the shalelayer allows mobilized hydrocarbons to flow from hydrocarbon layer 484Ato hydrocarbon layer 484B, allows drive fluids to be injected inhydrocarbon layer 484A, or allows steam drive processes (for example,SAGD, cyclic steam soak (CSS), sequential CSS and SAGD or steam flood,or simultaneous SAGD and CSS) to be performed in hydrocarbon layer 484A.

In some embodiments, conductive layers are selected to provide lateralcontinuity of conductivity within the conductive layer and to provide asubstantially higher conductivity, for a given thickness, than thesurrounding hydrocarbon layer. Thin conductive layers selected on thisbasis may substantially confine the heat generation within and aroundthe conductive layers and allow much greater spacing between rows ofelectrodes. In some embodiments, layers to be heated are selected, onthe basis of resistivity well logs, to provide lateral continuity ofconductivity. Selection of layers to be heated is described in U.S. Pat.No. 4,926,941 to Glandt et al., which is incorporated herein byreference.

Once fluid injectivity is created, fluid may be injected in layer 1986through an injection well and/or conduit 1980 to heat or mobilize fluidsin hydrocarbon layer 484B. Fluids may be produced from hydrocarbon layer484B and/or other sections of the formation. In some embodiments, fluidis injected in conduit 1982 to mobilize and/or heat in hydrocarbon layer484A. Heated and/or mobilized fluids may be produced from conduit 1980and/or other production wells located in hydrocarbon layer 484B and/orother sections of the formation.

In certain embodiments, a solvation fluid, in combination with apressurizing fluid, is used to treat the hydrocarbon formation inaddition to the in situ heat treatment process. In some embodiments, asolvation fluid, in combination with a pressurizing fluid, is used afterthe hydrocarbon formation has been treated using a drive process. Insome embodiments, solvating fluids are foamed or made into foams toimprove the efficiency of the drive process. Since an effectiveviscosity of the foam may be greater than the viscosity of theindividual components, the use of a foaming composition may improve thesweep efficiency of drive fluids.

In some embodiments, the solvating fluid includes a foaming composition.The foaming composition may be injected simultaneously or alternatelywith pressurizing fluid and/or drive fluid to form foam in the heatedsection. Use of foaming compositions may be more advantageous than useof polymer solutions since foaming compositions are thermally stable attemperatures up to 600° C. while polymer compositions may degrade attemperatures above 150° C. Use of foaming compositions at temperaturesabove about 150° C. may allow more hydrocarbon fluids and/or moreefficient removal of hydrocarbons from the formation as compared to useof polymer compositions.

Foaming compositions may include, but are not limited to, surfactants.In certain embodiments, the foaming composition includes a polymer, asurfactant and/or an inorganic base, water, steam, and/or brine. Theinorganic base may include, but is not limited to, sodium hydroxide,potassium hydroxide, potassium carbonate, potassium bicarbonate, sodiumcarbonate, sodium bicarbonate, or mixtures thereof. Polymers includepolymers soluble in water or brine such as ethylene oxide or propyleneoxide polymers.

Surfactants include ionic surfactants and/or nonionic surfactants.Examples of ionic surfactants include alpha-olefinic sulfonates, alkylsodium sulfonates, and/or sodium alkyl benzene sulfonates. Non-ionicsurfactants include triethanolamine. Surfactants capable of formingfoams include, but are not limited to, alpha-olefinic sulfonates,alkylpolyalkoxyalkylene sulfonates, aromatic sulfonates, alkyl aromaticsulfonates, alcohol ethoxy glycerol sulfonates (AEGS), or mixturesthereof. Non-limiting examples of surfactants capable of being foamedinclude, sodium dodecyl 3EO sulfate, sodium dodecyl (Guerbert) 3POsulfate⁶³, ammonium isotridecyl(Guerbert) 4PO sulfate⁶³, sodiumtetradecyl (Guerbert) 4PO sulfate⁶³, and AEGS 25-12 surfactant. Nonionicand ionic surfactants and/or methods of use and/or methods of foamingfor treating a hydrocarbon formation are described in U.S. Pat. Nos.4,643,256 to Dilgren et al.; 5,193,618 to Loh et al.; 5,046,560 toTeletzke et al.; 5,358,045 to Sevigny et al.; 6,439,308 to Wang;7,055,602 to Shpakoff et al.; 7,137,447 to Shpakoff et al.; 7,229,950 toShpakoff et al.; and 7,262,153 to Shpakoff et al.; and by Wellington etal, in “Surfactant-Induced Mobility Control for Carbon Dioxide Studiedwith Computerized Tomography,” American Chemical Society SymposiumSeries No. 373, 1988, all of which are incorporated herein by reference.

Foam may be formed in the formation by injecting the foaming compositionduring or after addition of steam. Pressurizing fluid (for example,carbon dioxide, methane and/or nitrogen) may be injected in theformation before, during, or after the foaming composition is injected.A type of pressurizing fluid may be based on the surfactant used in thefoaming composition. For example, carbon dioxide may be used withalcohol ethoxy glycerol sulfonates. The pressurizing fluid and foamingcomposition may mix in the formation and produce foam. In someembodiments, non-condensable gas is mixed with the foaming compositionprior to injection to form a pre-foamed composition. The foamcomposition, the pressurizing fluid, and/or the pre-foamed compositionmay be periodically injected in the heated formation. The foamingcomposition, pre-foamed compositions, drive fluids, and/or pressurizingfluids may be injected at a pressure sufficient to displace theformation fluids without fracturing the reservoir.

In some embodiments, electrodes may be positioned in wellbores to heathydrocarbon layers in a subsurface formation. Electrodes may bepositioned vertically in the hydrocarbon formation or orientedsubstantially horizontal or inclined. Heating hydrocarbon formationswith electrodes is described in U.S. Pat. Nos. 4,084,537 to Todd;4,926,941 to Glandt et al.; and 5,046,559 to Glandt, all of which areincorporate herein by reference in their entirety. Electrodes used forheating hydrocarbon formations may have bare elements at the ends of theelectrodes. Heating of the hydrocarbon layers may subject the bareelement ends to increased current because of the near and far fieldvoltage fields concentrating on the ends. Coating of the electrode toform high voltage stress cones (“stress grading”) around sections of theelectrode or the entire electrode may enhance the performance of theelectrode. FIG. 310A depicts a schematic of an embodiment of anelectrode with a sleeve over a section of the electrode. FIG. 310Bdepicts a schematic of an embodiment of an uncoated electrode. FIG. 311Adepicts a schematic of another embodiment of a coated electrode. FIG.311B depicts a schematic of another embodiment of an uncoated electrode.Electrode 2012 may include a coating that forms sleeve 2010 around anend (as shown in FIG. 310A) or substantially all (as shown in FIG. 311A)of the electrode. Sleeve 2010 may be formed from a positive temperaturecoefficient polymer and/or a heat shrinkable material. When sleeve 2010is coated, as shown by arrows in FIGS. 310A and 311A, current flow isdistributed outwardly along sleeve 2010 when electrode 2012 is energizedrather than the ends or portions of the electrode, as shown in FIGS.310B and 311B.

In some embodiments, bulk resistance along sections of the electrode maybe increased by layering conductive materials and insulating layersalong a section of the electrode. Examples of such electrodes areelectrodes made by Raychem® (Tyco International Inc., Princeton, N.J.,U.S.A.). Increased bulk resistance may allow voltage along the sleeve ofthe electrode to be distributed, thus decreasing the current density atthe end of the electrode.

Many different types of wells or wellbores may be used to treat thehydrocarbon containing formation using the in situ heat treatmentprocess. In some embodiments, vertical and/or substantially verticalwells are used to treat the formation. In some embodiments, horizontal(such as J-shaped wells and/or L-shaped wells), and/or u-shaped wellsare used to treat the formation. In some embodiments, combinations ofhorizontal wells, vertical wells, and/or other combinations are used totreat the formation. In certain embodiments, wells extend through theoverburden of the formation to a hydrocarbon containing layer of theformation. Heat in the wells may be lost to the overburden. In certainembodiments, surface and/or overburden infrastructures used to supportheaters and/or production equipment in horizontal wellbores and/oru-shaped wellbores are large in size and/or numerous.

In certain embodiments, heaters, heater power sources, productionequipment, supply lines, and/or other heater or production supportequipment are positioned in substantially horizontal and/or inclinedtunnels. Positioning these structures in tunnels may allow smaller sizedheaters and/or other equipment to be used to treat the formation.Positioning these structures in tunnels may also reduce energy costs fortreating the formation, reduce emissions from the treatment process,facilitate heating system installation, and/or reduce heat loss to theoverburden, as compared to conventional hydrocarbon recovery processesthat utilize surface based equipment. U.S. Published Patent ApplicationNos. 2007-0044957 to Watson et al.; 2008-0017416 to Watson et al.; and2008-0078552 to Donnelly et al., all of which are incorporated herein byreference, describe methods of drilling from a shaft for undergroundrecovery of hydrocarbons and methods of underground recovery ofhydrocarbons.

FIG. 312 depicts a perspective view of underground treatment system1144. Underground treatment system 1144 may be used to treat hydrocarbonlayer 484 using the in situ heat treatment process. In certainembodiments, underground treatment system 1144 includes shafts 1146,utility shafts 1148, tunnels 1150A, tunnels 1150B, and wellbores 428.Tunnels 1150A, 1150B may be located in overburden 482, an underburden, anon-hydrocarbon containing layer, or a low hydrocarbon content layer ofthe formation. In some embodiments, tunnels 1150A, 1150B are located ina rock layer of the formation. In some embodiments, tunnels 1150A, 1150Bare located in an impermeable portion of the formation. For example,tunnels 1150A, 1150B may be located in a portion of the formation havingpermeability of about 1 millidarcy.

Shafts 1146 and/or utility shafts 1148 may be formed and strengthened(for example, supported to inhibit collapse) using methods known in theart. For example, shafts 1146 and/or utility shafts 1148 may be formedusing blind and raised bore drilling technologies using mud weight andlining to support the shafts. Conventional techniques may be used toraise and lower equipment in the shafts and/or to provide utilitiesthrough the shafts.

Tunnels 1150A, 1150B may be formed and strengthened (for example,supported to inhibit collapse) using methods known in the art. Forexample, tunnels 1150A, 1150B may be formed road-headers, drill andblast, tunnel boring machine, and/or continuous miner technologies toform the tunnels. Tunnel strengthening may be provided by, for example,roof support, mesh, and/or shot-crete. Tunnel strengthening may beneeded to inhibit tunnel collapse and/or to inhibit movement of thetunnels during heat treatment of the formation.

The status of tunnels 1150A, 1150B, shafts 1146, and/or utility shafts1148 may be monitored for changes in structure or integrity of thetunnels or shafts. For example, conventional mine survey technologiesmay be used to continuously monitor the structure and integrity of thetunnels and/or shafts. In addition, systems may be used to monitorchanges in characteristics of the formation that may affect thestructure and/or integrity of the tunnels or shafts.

Tunnels 1150A, 1150B may be substantially horizontal or inclined in theformation. In certain embodiments, tunnels 1150A extend along the lineof shafts 1146 and utility shafts 1148. Tunnels 1150B may connectbetween tunnels 1150A. In some embodiments, tunnels 1150B allowcross-access between tunnels 1150A. In some embodiments, tunnels 1150Bare used to cross-connect production between tunnels 1150A below thesurface of the formation.

Tunnels 1150A, 1150B may have cross-section shapes that are rectangular,circular, elliptical, or horseshoe-shaped. Tunnels 1150A, 1150B may havecross-sections large enough for personnel, equipment, and/or vehicles topass through the tunnels. In some embodiments, tunnels 1150A, 1150B havecross-sections large enough to allow personnel and/or vehicles to freelypass by equipment located in the tunnels. In some embodiments, tunnels1150A, 1150B have an average diameter of at least 1 m, at least 2 m, atleast 5 m, or at least 10 m.

In certain embodiments, shafts 1146 and/or utility shafts 1148 connectwith tunnels 1150A in overburden 482 (or another layer of theformation). Shafts 1146 and/or utility shafts 1148 may be sunk or formedusing methods known in the art for drilling and/or sinking mine shafts.In certain embodiments, shafts 1146 and/or utility shafts 1148 connectsurface 568 with tunnels 1150A in overburden 482 and/or hydrocarbonlayer 484. In some embodiments, shafts 1146 and/or utility shafts 1148extend into hydrocarbon layer 484. For example, shafts 1146 may includeproduction conduits and/or other production equipment to produce fluidsfrom hydrocarbon layer 484.

In certain embodiments, shafts 1146 and/or utility shafts 1148 aresubstantially vertical or slightly angled from vertical. In certainembodiments, shafts 1146 and/or utility shafts 1148 have cross-sectionslarge enough for personnel, equipment, and/or vehicles to pass throughthe shafts. In some embodiments, shafts 1146 and/or utility shafts 1148have circular cross-sections. In some embodiments, shafts 1146 and/orutility shafts 1148 have an average cross-sectional diameter of at least0.5 m, at least 1 m, at least 2 m, at least 5 m, or at least 10 m.

In certain embodiments, the distance between two shafts 1146 is between500 m and 5000 m, between 1000 m and 4000 m, or between 2000 m and 3000m. In some embodiments, the distance between two utility shafts 1148 isbetween 100 m and 1000 m, between 250 m and 750 m, or between 400 m and600 m.

In certain embodiments, shafts 1146 are larger in cross-section thanutility shafts 1148. Shafts 1146 may allow access to tunnels 1150A forlarge ventilation, materials, equipment, vehicles, and personnel.Utility shafts 1148 may provide service corridor access to tunnels 1150Afor equipment or structures such as, but not limited to, power supplylegs, production risers, and/or ventilation openings. In someembodiments, shafts 1146 and/or utility shafts 1148 include monitoringand/or sealing systems to monitor and assess gas levels in the shaftsand to seal off the shafts if needed.

FIG. 313 depicts an exploded perspective view of a portion ofunderground treatment system 1144 and tunnels 1150A. In certainembodiments, tunnels 1150A include heater tunnels 1152 and/or utilitytunnels 1154. In some embodiments, tunnels 1150A include additionaltunnels such as access tunnels and/or service tunnels. FIG. 314 depictsan exploded perspective view of a portion of underground treatmentsystem 1144 and tunnels 1150A. Tunnels 1150A, as shown in FIG. 314, mayinclude heater tunnels 1152, utility tunnels 1154, and/or access tunnels1155.

In certain embodiments, as shown in FIG. 313, wellbores 428 extend fromheater tunnels 1152. Wellbores 428 may include, but not be limited to,heater wells, heat source wells, production wells, injection wells (forexample, steam injection wells), and/or monitoring wells. Heaters and/orheat sources that may be located in wellbores 428 include, but are notlimited to, electric heaters, oxidation heaters (gas burners), heaterscirculating a heat transfer fluid, closed looped molten salt circulatingsystems, pulverized coal systems, and/or joule heat sources (heating ofthe formation using electrical current flow between heat sources in twowellbores in the formation). The wellbores used for joule heat sourcesmay extend from the same tunnel (for example, substantially parallelwellbores extending between two tunnels with electrical current flowingbetween the wellbores) or from different tunnels (for example, wellboresextending from two different tunnels that are spaced to allow electricalcurrent flow between the wellbores).

Introduction of heat sources through heater tunnels 1152 allowshydrocarbon layer 484 to be heated without significant heat losses tooverburden 482. Being able to provide heat mainly to hydrocarbon layer484 with low heat losses in the overburden may enhance heaterefficiency. Using tunnels to provide heaters only in the hydrocarbonlayer, and not requiring heater wellbore sections in the overburden, maydecrease heater costs by at least 30%, at least 50%, at least 60%, or atleast 70% as compared to heater costs using heaters that have sectionspassing through the overburden.

Providing heaters through tunnels may allow higher heat source densitiesin the hydrocarbon layer 484 to be obtained. Higher heat sourcedensities may result in faster production of hydrocarbons from theformation. Closer spacing of heaters may be economically beneficial dueto a significantly lower cost per additional heater. For example,heaters located in the hydrocarbon layer by drilling through theoverburden are typically spaced about 12 m apart. Installing heatersfrom tunnels may allow heaters to be spaced about 8 m apart in thehydrocarbon layer. The closer spacing may accelerate first production toabout 2 years as compared to the 5 years for first production obtainedfrom heaters that are spaced 12 m apart and accelerate completion ofproduction to about 5 years from about 8 years. This acceleration infirst production may reduce the heating requirement 5% or more.

In certain embodiments, subsurface connections for heaters or heatsources are made in heater tunnels 1152. Connections that are made inheater tunnels 1152 include, but are not limited to, insulatedelectrical connections, physical support connections, andinstrumental/diagnostic connections. For example, electrical connectionmay be made between electric heater elements and bus bars located inheater tunnels 1152. The bus bars may be used to provide electricalconnection to the ends of the heater elements. In certain embodiments,connections made in heater tunnels 1152 are made at a certain safetylevel. For example, the connections are made such that there is littleor no explosion risk (or other potential hazards) in the heater tunnelsbecause of gases from the heat sources or the heat source wellbores thatmay migrate to heater tunnels 1152. In some embodiments, heater tunnels1152 are ventilated to the surface or another area to lower theexplosion risk in the heater tunnels. For example, heater tunnels 1152may be vented through utility shafts 1148.

In certain embodiments, heater connections are made between heatertunnels 1152 and utility tunnels 1154. For example, electricalconnections from electric heaters extending heater tunnels 1152 may bemade into utility tunnels 1154. These connections may be substantiallysealed such that there is little or no leaking between the tunnelseither through or around the connections.

Utility tunnels 1154 may include power equipment or other equipmentnecessary to operate heat sources and/or production equipment. Incertain embodiments, transformers 1156 and voltage regulators 1158 arelocated in utility tunnels 1154. Having transformers 1156 and voltageregulators 1158 in the subsurface allows high-voltage to be transporteddirectly into the overburden of the formation to increase the efficiencyof providing power to heaters in the formation.

Transformers 1156 may be, for example, gas insulated, water cooledtransformers such as SF₆ gas-insulated power transformers available fromToshiba Corporation (Tokyo, Japan). Such transformers may be highefficiency transformers. These transformers may be used to provideelectricity to multiple heaters in the formation. The higher efficiencyof these transformers reduces water cooling requirements for thetransformers. Water cooling the transformers allows the transformers tobe placed in small chambers without the need for extra cooling to keepthe transformers from overheating. Water cooling instead of air coolingallows more heat per volume of cooling fluid to be transported to thesurface versus air cooling. Using gas-insulated transformers eliminatesthe use of flammable oils that may be hazardous in the undergroundenvironment.

In some embodiments, transformers 1156 and/or voltage regulators 1158are located in side chambers of utility tunnels 1154. Locatingtransformers 1156 and/or voltage regulators 1158 in side chambers movesthe transformers and/or voltage regulators out of the way of personnel,equipment, and/or vehicles moving through utility tunnels 1154. Supplylines (for example, supply lines 204 depicted in FIG. 320) in utilityshaft 1148 may supply power to voltage regulators 1158 and transformers1156 in utility tunnels 1154.

In some embodiments and as shown in FIG. 313, voltage regulators arelocated in power chambers 1160. Power chambers 1160 may connect toutility tunnels 1154 or be side chambers of the utility tunnels. Powermay be brought into power chambers 1160 through utility shafts 1148. Useof utility tunnels 1154 may allow easier, quicker, and/or more effectivemaintenance, repair, and/or replacement of the connections made to heatsources in the subsurface.

In certain embodiments, sections of heater tunnels 1152 and utilitytunnels 1154 are interconnected by connecting tunnels 1168. Connectingtunnels 1168 may allow access between heater tunnels 1152 and utilitytunnels 1154. Connecting tunnels 1168 may include airlocks or otherstructures to provide a seal that can be opened and closed betweenheater tunnels 1152 and utility tunnels 1154.

In some embodiments, heater tunnels 1152 include pipelines 208 or otherconduits. In some embodiments, pipelines 208 are used to produce fluids(for example, formation fluids such as hydrocarbon fluids) fromproduction wells or heater wells coupled to heater tunnels 1152. In someembodiments, pipelines 208 are used to provide fluids used in productionwells or heater wells (for example, heat transfer fluids for circulatingfluid heaters or gas for gas burners). Pumps and associated equipment1172 for pipelines 208 may be located in pipeline chambers 1174. In someembodiment, pipeline chambers 1174 are isolated (sealed off) from heatertunnels 1154. Fluids may be provided to and/or removed from pipelinechambers 1174 using risers and/or pumps located in utility shafts 1148.

In some embodiments, heat sources are used in wellbores 428 proximateheater tunnels 1152 to control viscosity of formation fluids beingproduced from the formation. The heat sources may have various lengthsand/or provide different amounts of heat at different locations in theformation. In some embodiments, the heat sources are located inwellbores 428 used for producing fluids from the formation (for example,production wells).

As shown in FIG. 312, wellbores 428 may extend between tunnels 1150A inhydrocarbon layer 484. Tunnels 1150A may include one or more of heatertunnels 1152, utility tunnels 1154, and/or access tunnels 1155. In someembodiments, access tunnels 1155 are used as ventilation tunnels. Itshould be understood that the any number of tunnels and/or any order oftunnels may be used as contemplated or desired.

In some embodiments, heated fluid may flow through wellbores 428 or heatsources 202 that extend between tunnels 1150A. For example, heated fluidmay flow between a first heater tunnel and a second heater tunnel. Thesecond tunnel may include a production system that is capable ofremoving the heated fluids from the formation to the surface of theformation. In some embodiments, the second tunnel includes equipmentthat collects heated fluids from at least two wellbores. In someembodiments, the heated fluids are moved to the surface using a liftsystem. The lift system may be located in utility shaft 1148 or aseparate production wellbore.

FIG. 315 depicts a side view representation of an embodiment for flowingheated fluid in heat sources 202 between tunnels 1150A. FIG. 316 depictsa top view representation of the embodiment depicted in FIG. 315.Circulation system 992 may circulate heated fluid (for example, moltensalt) through heat sources 202. Shafts 1148 and tunnels 1150A may beused to provide the heated fluid to the heat sources and return theheated fluid from the heat sources. Large piping may be used in shafts1148 and tunnels 1150A. The large piping may minimize pressure drops intransporting the heated fluid through the overburden of the formation.Piping in shafts 1148 and tunnels 1150A may be insulated to inhibit heatlosses in the overburden.

FIG. 317 depicts another perspective view of an embodiment ofunderground treatment system 1144 with wellbores 428 extending betweentunnels 1150A. In certain embodiments, wellbores 428 extend fromwellbore chambers 2024. Wellbore chambers 2024 may be connected to thesides of tunnels 1150A.

FIG. 318 depicts a top view of an embodiment of tunnels 1150A withwellbore chambers 2024. In certain embodiments, power chambers 1160 areconnected to utility tunnel 1154. Transformers 1156 and/or other powerequipment may be located in power chambers 1160.

In certain embodiments, tunnels 1150A includes heater tunnel 1152 andutility tunnel 1154. Heater tunnel 1152 may be connected to utilitytunnel 1154 with connecting tunnel 1168. Wellbore chambers 2024 areconnected to heater tunnel 1152. In certain embodiments, wellborechambers 2024 include heater wellbore chambers 2024A and adjunctwellbore chambers 2024B. Heat sources 202 (for example, heaters) mayextend from heater wellbore chambers 2024A. Heater wellbore chambers2024A may have angled side walls with respect to heater tunnel 1152 toallow heat sources to be installed into the chambers more easily. Theheaters may have limited bending capability and the angled walls mayallow the heaters to be installed into the chambers without overbendingthe heaters.

In certain embodiments, barrier 2026 seals off heater wellbore chambers2024A from heater tunnel 1152. Barrier 2026 may be a fire and/or blastresistant barrier (for example, a concrete wall). In some embodiments,barrier 2026 includes an access port (for example, an access door) toallow entry into the chambers. Heater wellbore chambers 2024A may besealed off from heater tunnel 1152 after heat sources 202 have beeninstalled. Utility shaft 1148 may provide ventilation into heaterwellbore chambers 2024A. In some embodiments, utility shaft 1148 is usedto provide a fire or blast suppression fluid into heater wellborechambers 2024A.

In certain embodiments, adjunct wellbores 428A extend from adjunctwellbore chambers 2024B. Adjunct wellbores 428A may include wellboresused as, for example, infill wellbores (repair wellbores) orintervention wellbores for killing leaks, and/or monitoring wellbores.Barrier 2026 may seal off adjunct wellbore chambers 2024B from heatertunnel 1152. In some embodiments, heater wellbore chambers 2024A and/oradjunct wellbore chambers 2024B are cemented in (the chambers are filledwith cement). Filling the chambers with cement substantially seals offthe chambers from inflow or outflow of fluids.

As shown in FIGS. 312 and 317, wellbores 428 may be formed betweentunnels 1150A. Wellbores 428 may be formed substantially vertically,substantially horizontally, or inclined in hydrocarbon layer 484 bydrilling into the hydrocarbon layer from tunnels 1150A. Wellbores 428may be formed using drilling techniques known in the art. For example,wellbores 428 may be formed using pneumatic drilling using coiled tubingavailable from Penguin Automated Systems (Naughton, Ontario, Canada).

Drilling wellbores 428 from tunnels 1150A may increase drillingefficiency and decrease drilling time and allow for longer wellboresbecause the wellbores do not have to be drilled through overburden 482.Tunnels 1150A may allow large surface footprint equipment to be placedin the subsurface instead of at the surface. Drilling from tunnels 1150Aand subsequent placement of equipment and/or connections in the tunnelsmay reduce a surface footprint as compared to conventional surfacedrilling methods that use surface based equipment and connections.

Using shafts and tunnels in combination with in situ heat treatment of ahydrocarbon containing formation to produce hydrocarbons from theformation may be beneficial because the overburden section is eliminatedfrom wellbore construction, heater construction, and/or drillingrequirements. In some embodiments, a least a portion of the shafts andtunnels are located below aquifers in or above the hydrocarboncontaining formation. Locating the shafts and tunnels below the aquifersmay reduce contamination risk to the aquifers, and may simplifyabandonment of the shafts and tunnels after treatment of the formation.

In certain embodiments, underground treatment system 1144 (depicted inFIGS. 312, 313, 317, 321, and 320) includes one or more seals to sealthe tunnels and shafts from the formation pressure and formation fluids.For example, the underground treatment system may include one or moreimpermeable barriers to seal personnel workspace from the formation. Insome embodiments, wellbores are sealed off with impermeable barriers tothe tunnels and shafts to inhibit fluids from entering the tunnels andshafts from the wellbores. In some embodiments, the impermeable barriersinclude cement or other packing materials. In some embodiments, theseals include valves or valve systems, airlocks, or other sealingsystems known in the art. The underground treatment system may includeat least one entry/exit point to the surface for access by personnel,vehicles, and/or equipment.

FIG. 319 depicts a top view of an embodiment of development of tunnels1150A. Heater tunnel 1152 may include heat source section 1162,connecting section 1164, and/or drilling section 1166 as the heatertunnel is being formed left to right. In heat source section 1162,wellbores 428 have been formed and heat sources have been introducedinto the wellbores. In some embodiments, heat source section 1162 isconsidered a hazardous confined space. Heat source section 1162 may beisolated from other sections in heater tunnel 1152 and/or utility tunnel1154 with material impermeable to hydrocarbon gases and/or hydrogensulfide. For example, cement or another impermeable material may be usedto seal off heat source section 1162 from heater tunnel 1152 and/orutility tunnel 1154. In some embodiments, impermeable material is usedto seal off heat source section 1162 from the heated portion of theformation to inhibit formation fluids or other hazardous fluids fromentering the heat source section. In some embodiments, at least 30 m, atleast 40 m, or at least 50 m of wellbore is between the heat sources andheater tunnel 1152. In some embodiments, shaft 1146 proximate to heatertunnel 1152 is sealed (for example, filled with cement) after heatinghas been initiated in the hydrocarbon layer to inhibit gas or otherfluids from entering the shaft.

In some embodiments, heaters controls may be located in utility tunnel1154. In some embodiments, utility tunnel 1154 includes electricalconnections, combustors, tanks, and/or pumps necessary to supportheaters and/or heat transport systems. For example, transformers 1156may be located in utility tunnel 1154.

Connecting section 1164 may be located after heat source section 1162.Connecting section 1164 may include space for performing operationsnecessary for installing the heat sources and/or connecting heat sources(for example, making electrical connections to the heaters). In someembodiments, connections and/or movement of equipment in connectingsection 1164 is automated using robotics or other automation techniques.Drilling section 1166 may be located after connecting section 1164.Additional wellbores may be dug and/or the tunnel may be extended indrilling section 1166.

In certain embodiments, operations in heat source section 1162,connecting section 1164, and/or drilling section 1166 are independent ofeach other. Heat source section 1162, connecting section 1164, and/orproduction section 1166 may have dedicated ventilation systems and/orconnections to utilities tunnel 1154. Connecting tunnels 1168 may allowaccess and egress to heat source section 1162, connecting section 1164,and/or drilling section 1166.

In certain embodiments, connecting tunnels 1168 include airlocks 1170and/or other barriers. Airlocks 1170 may help regulate the relativepressures such that the pressure in heat source section 1162 is lessthan the air pressure in connecting section 1164, which is less than theair pressure in drilling section 1166. Air flow may move into heatsource section 1162 (the most hazardous area) to reduce the probabilityof a flammable atmosphere in utility tunnel 1154, connecting section1164, and/or drilling section 1166. Airlocks 1170 may include suitablegas detection and alarms to ensure transformers or other electricalequipment are de-energized in the event that an unsafe flammable limitis encountered in the utility tunnel 1154 (for example, less thanone-half of the lower flammable limit). Automated controls may be usedto operate airlocks 1170 and/or the other barriers. Airlocks 1170 may beoperated to allow personnel controlled access and/or egress duringnormal operations and/or emergency situations.

In certain embodiments, heat sources located in wellbores extending fromtunnels are used to heat the hydrocarbon layer. The heat from the heatsources may mobilize hydrocarbons in the hydrocarbon layer and themobilized hydrocarbons flow towards production wells. Production wellsmay be positioned in the hydrocarbon layer below, adjacent, or above theheat sources to produce the mobilized fluids. In some embodiments,formation fluids may gravity drain into tunnels located in thehydrocarbon layer. Production systems may be installed in the tunnels(for example, pipeline 208 depicted in FIG. 313). The tunnel productionsystems may be operated from surface facilities and/or facilities in thetunnel. Piping, holding facilities, and/or production wells may belocated in a production portion of the tunnels to be used to produce thefluids from the tunnels. The production portion of the tunnels may besealed with an impervious material (for example, cement or a steelliner). The formation fluids may be pumped to the surface through ariser and/or vertical production well located in the tunnels. In someembodiments, formation fluids from multiple horizontal productionwellbores drain into one vertical production well located in one tunnel.The formation fluids may be produced to the surface through the verticalproduction well.

In some embodiments, a production wellbore extending directly from thesurface to the hydrocarbon layer is used to produce fluids from thehydrocarbon layer. FIG. 320 depicts production well 206 extending fromthe surface into hydrocarbon layer 484. In certain embodiments,production well 206 is substantially horizontally located in hydrocarbonlayer 484. Production well 206 may, however, have any orientationdesired. For example, production well 206 may be a substantiallyvertical production well.

In some embodiments, as shown in FIG. 320, production well 206 isdrilled from the surface of the formation and heat sources 202 aredrilled from tunnels 1150A in overburden 482 or another impermeablelayer of the formation. Having the production well separated from thetunnels used to provide heat sources into the formation may reduce risksassociated with having hot formation fluids (for example, hothydrocarbon fluids) in the tunnels and near electrical equipment orother heater equipment. In some embodiments, the distance between thelocation of production wells on the surface and the location of fluidintakes, ventilation intakes, and/or other possible intakes into thetunnels below the surface is maximized to minimize the risk of fluidsreentering the formation through the intakes.

In some embodiments, wellbores 428 interconnect with utility tunnels1154 or other tunnels below the overburden of the formation. FIG. 321depicts a side view of an embodiment of underground treatment system1144. In some embodiments, wellbores 428 are directionally drilled toutility tunnels 1154 in hydrocarbon layer 484. Wellbores 428 may bedirectional drilled from the surface or from tunnels located inoverburden 482. Directional drilling to intersect utility tunnel 1154 inhydrocarbon layer 484 may be easier than directional drilling tointersect another wellbore in the formation. Drilling equipment such as,but not limited to, magnetic transmission equipment, magnetic sensingequipment, acoustic transmission equipment, and acoustic sensingequipment may be located in utility tunnels 1154 and used fordirectional drilling of wellbores 428. The drilling equipment may beremoved from utility tunnels 1154 after directional drilling iscompleted.

EXAMPLES

Non-restrictive examples are set forth below.

Temperature Limited Heater Experimental Data

FIGS. 322-337 depict experimental data for temperature limited heaters.FIG. 322 depicts electrical resistance (Ω) versus temperature (° C.) atvarious applied electrical currents for a 446 stainless steel rod with adiameter of 2.5 cm and a 410 stainless steel rod with a diameter of 2.5cm. Both rods had a length of 1.8 m. Curves 1176-1182 depict resistanceprofiles as a function of temperature for the 446 stainless steel rod at440 amps AC (curve 1176), 450 amps AC (curve 1178), 500 amps AC (curve1180), and 10 amps DC (curve 1182). Curves 1184-1190 depict resistanceprofiles as a function of temperature for the 410 stainless steel rod at400 amps AC (curve 1184), 450 amps AC (curve 1186), 500 amps AC (curve1188), 10 amps DC (curve 1190). For both rods, the resistance graduallyincreased with temperature until the Curie temperature was reached. Atthe Curie temperature, the resistance fell sharply. Above the Curietemperature, the resistance decreased slightly with increasingtemperature. Both rods show a trend of decreasing resistance withincreasing AC current. Accordingly, the turndown ratio decreased withincreasing current. Thus, the rods provide a reduced amount of heat nearand above the Curie temperature of the rods. In contrast, the resistancegradually increased with temperature through the Curie temperature withthe applied DC current.

FIG. 323 shows electrical resistance (Ω) profiles as a function oftemperature (° C.) at various applied electrical currents for a copperrod contained in a conduit of Sumitomo HCM12A (a high strength 410stainless steel). The Sumitomo conduit had a diameter of 5.1 cm, alength of 1.8 m, and a wall thickness of about 0.1 cm. Curves 1192-1202show that at all applied currents (1192: 300 amps AC; 1194: 350 amps AC;1196: 400 amps AC; 1198: 450 amps AC; 1200: 500 amps AC; 1202: 550 ampsAC), resistance increased gradually with temperature until the Curietemperature was reached. At the Curie temperature, the resistance fellsharply. As the current increased, the resistance decreased, resultingin a smaller turndown ratio.

FIG. 324 depicts electrical resistance (Ω) versus temperature (° C.) atvarious applied electrical currents for a temperature limited heater.The temperature limited heater included a 4/0 MGT-1000 furnace cableinside an outer conductor of ¾″ Schedule 80 Sandvik (Sweden) 4C54 (446stainless steel) with a 0.30 cm thick copper sheath welded onto theoutside of the Sandvik 4C54 and a length of 1.8 m. Curves 1204 through1222 show resistance profiles as a function of temperature for ACapplied currents ranging from 40 amps to 500 amps (1204: 40 amps; 1206:80 amps; 1208: 120 amps; 1210: 160 amps; 1212: 250 amps; 1214: 300 amps;1216: 350 amps; 1218: 400 amps; 1220: 450 amps; 1222: 500 amps). FIG.325 depicts the raw data for curve 1218. FIG. 326 depicts the data forselected curves 1214, 1216, 1218, 1220, 1222, and 1224. At lowercurrents (below 250 amps), the resistance increased with increasingtemperature up to the Curie temperature. At the Curie temperature, theresistance fell sharply. At higher currents (above 250 amps), theresistance decreased slightly with increasing temperature up to theCurie temperature. At the Curie temperature, the resistance fellsharply. Curve 1224 shows resistance for an applied DC electricalcurrent of 10 amps. Curve 1224 shows a steady increase in resistancewith increasing temperature, with little or no deviation at the Curietemperature.

FIG. 327 depicts power (watts per meter (W/m)) versus temperature (° C.)at various applied electrical currents for a temperature limited heater.The temperature limited heater included a 4/0 MGT-1000 furnace cableinside an outer conductor of ¾″ Schedule 80 Sandvik (Sweden) 4C54 (446stainless steel) with a 0.30 cm thick copper sheath welded onto theoutside of the Sandvik 4C54 and a length of 1.8 m. Curves 1226-1234depict power versus temperature for AC applied currents of 300 amps to500 amps (1226: 300 amps; 1228: 350 amps; 1230: 400 amps; 1232: 450amps; 1234: 500 amps). Increasing the temperature gradually decreasedthe power until the Curie temperature was reached. At the Curietemperature, the power decreased rapidly.

FIG. 328 depicts electrical resistance (mΩ) versus temperature (° C.) atvarious applied electrical currents for a temperature limited heater.The temperature limited heater included a copper rod with a diameter of1.3 cm inside an outer conductor of 2.5 cm Schedule 80 410 stainlesssteel pipe with a 0.15 cm thick copper Everdur™ (DuPont Engineering,Wilmington, Del., U.S.A.) welded sheath over the 410 stainless steelpipe and a length of 1.8 m. Curves 1236-1246 show resistance profiles asa function of temperature for AC applied currents ranging from 300 ampsto 550 amps (1236: 300 amps; 1238: 350 amps; 1240: 400 amps; 1242: 450amps; 1244: 500 amps; 1246: 550 amps). For these AC applied currents,the resistance gradually increases with increasing temperature up to theCurie temperature. At the Curie temperature, the resistance fallssharply. In contrast, curve 1248 shows resistance for an applied DCelectrical current of 10 amps. This resistance shows a steady increasewith increasing temperature, and little or no deviation at the Curietemperature.

FIG. 329 depicts data of electrical resistance (mΩ) versus temperature(° C.) for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rodat various applied electrical currents. Curves 1250, 1252, 1254, 1256,and 1258 depict resistance profiles as a function of temperature for the410 stainless steel rod at 40 amps AC (curve 1256), 70 amps AC (curve1258), 140 amps AC (curve 1250), 230 amps AC (curve 1252), and 10 ampsDC (curve 1254). For the applied AC currents of 140 amps and 230 amps,the resistance increased gradually with increasing temperature until theCurie temperature was reached. At the Curie temperature, the resistancefell sharply. In contrast, the resistance showed a gradual increase withtemperature through the Curie temperature for the applied DC current.

FIG. 330 depicts data of electrical resistance (mΩ) versus temperature(° C.) for a composite 1.75 inch (1.9 cm) diameter, 6 foot (1.8 m) longAlloy 42-6 rod with a 0.375 inch diameter copper core (the rod has anoutside diameter to copper diameter ratio of 2:1) at various appliedelectrical currents. Curves 1260, 1262, 1264, 1266, 1268, 1270, 1272,and 1274 depict resistance profiles as a function of temperature for thecopper cored alloy 42-6 rod at 300 A AC (curve 1260), 350 A AC (curve1262), 400 A AC (curve 1264), 450 A AC (curve 1266), 500 A AC (curve1268), 550 A AC (curve 1270), 600 A AC (curve 1272), and 10 A DC (curve1274). For the applied AC currents, the resistance decreased graduallywith increasing temperature until the Curie temperature was reached. Asthe temperature approaches the Curie temperature, the resistancedecreased more sharply. In contrast, the resistance showed a gradualincrease with temperature for the applied DC current.

FIG. 331 depicts data of power output (watts per foot (W/ft)) versustemperature (° C.) for a composite 1.75 inch (1.9 cm) diameter, 6 foot(1.8 m) long Alloy 42-6 rod with a 0.375 inch diameter copper core (therod has an outside diameter to copper diameter ratio of 2:1) at variousapplied electrical currents. Curves 1276, 1278, 1280, 1282, 1284, 1286,1288, and 1290 depict power as a function of temperature for the coppercored alloy 42-6 rod at 300 A AC (curve 1276), 350 A AC (curve 1278),400 A AC (curve 1280), 450 A AC (curve 1282), 500 A AC (curve 1284), 550A AC (curve 1286), 600 A AC (curve 1288), and 10 A DC (curve 1290). Forthe applied AC currents, the power output decreased gradually withincreasing temperature until the Curie temperature was reached. As thetemperature approaches the Curie temperature, the power output decreasedmore sharply. In contrast, the power output showed a relatively flatprofile with temperature for the applied DC current.

FIG. 332 depicts data for values of skin depth (cm) versus temperature(° C.) for a solid 2.54 cm diameter, 1.8 m long 410 stainless steel rodat various applied AC electrical currents. The skin depth was calculatedusing EQN. 17:δ=R ₁ −R ₁×(1−(1/R _(AC) /R _(DC)))^(1/2);  (EQN. 17)where δ is the skin depth, R₁ is the radius of the cylinder, R_(AC) isthe AC resistance, and R_(DC) is the DC resistance. In FIG. 332, curves1292-1310 show skin depth profiles as a function of temperature forapplied AC electrical currents over a range of 50 amps to 500 amps(1292: 50 amps; 1294: 100 amps; 1296: 150 amps; 1298: 200 amps; 1300:250 amps; 1302: 300 amps; 1304: 350 amps; 1306: 400 amps; 1380: 450amps; 1310: 500 amps). For each applied AC electrical current, the skindepth gradually increased with increasing temperature up to the Curietemperature. At the Curie temperature, the skin depth increased sharply.

FIG. 333 depicts temperature (° C.) versus time (hrs) for a temperaturelimited heater. The temperature limited heater was a 1.83 m long heaterthat included a copper rod with a diameter of 1.3 cm inside a 2.5 cmSchedule XXH 410 stainless steel pipe and a 0.325 cm copper sheath. Theheater was placed in an oven for heating. Alternating current wasapplied to the heater when the heater was in the oven. The current wasincreased over two hours and reached a relatively constant value of 400amps for the remainder of the time. Temperature of the stainless steelpipe was measured at three points at 0.46 m intervals along the lengthof the heater. Curve 1314 depicts the temperature of the pipe at a point0.46 m inside the oven and closest to the lead-in portion of the heater.Curve 1316 depicts the temperature of the pipe at a point 0.46 m fromthe end of the pipe and furthest from the lead-in portion of the heater.Curve 1318 depicts the temperature of the pipe at about a center pointof the heater. The point at the center of the heater was furtherenclosed in a 0.3 m section of 2.5 cm thick Fiberfrax® (Unifrax Corp.,Niagara Falls, N.Y., U.S.A.) insulation. The insulation was used tocreate a low thermal conductivity section on the heater (a section whereheat transfer to the surroundings is slowed or inhibited (a “hotspot”)). The temperature of the heater increased with time as shown bycurves 1318, 1316, and 1314. Curves 1318, 1316, and 1314 show that thetemperature of the heater increased to about the same value for allthree points along the length of the heater. The resulting temperatureswere substantially independent of the added Fiberfrax® insulation. Thus,the operating temperatures of the temperature limited heater weresubstantially the same despite the differences in thermal load (due tothe insulation) at each of the three points along the length of theheater. Thus, the temperature limited heater did not exceed the selectedtemperature limit in the presence of a low thermal conductivity section.

FIG. 334 depicts temperature (° C.) versus log time (hrs) data for a 2.5cm solid 410 stainless steel rod and a 2.5 cm solid 304 stainless steelrod. At a constant applied AC electrical current, the temperature ofeach rod increased with time. Curve 1320 shows data for a thermocoupleplaced on an outer surface of the 304 stainless steel rod and under alayer of insulation. Curve 1322 shows data for a thermocouple placed onan outer surface of the 304 stainless steel rod without a layer ofinsulation. Curve 1324 shows data for a thermocouple placed on an outersurface of the 410 stainless steel rod and under a layer of insulation.Curve 1326 shows data for a thermocouple placed on an outer surface ofthe 410 stainless steel rod without a layer of insulation. A comparisonof the curves shows that the temperature of the 304 stainless steel rod(curves 1320 and 1322) increased more rapidly than the temperature ofthe 410 stainless steel rod (curves 1324 and 1326). The temperature ofthe 304 stainless steel rod (curves 1320 and 1322) also reached a highervalue than the temperature of the 410 stainless steel rod (curves 1324and 1326). The temperature difference between the non-insulated sectionof the 410 stainless steel rod (curve 1326) and the insulated section ofthe 410 stainless steel rod (curve 1324) was less than the temperaturedifference between the non-insulated section of the 304 stainless steelrod (curve 1322) and the insulated section of the 304 stainless steelrod (curve 1320). The temperature of the 304 stainless steel rod wasincreasing at the termination of the experiment (curves 1320 and 1322)while the temperature of the 410 stainless steel rod had leveled out(curves 1324 and 1326). Thus, the 410 stainless steel rod (thetemperature limited heater) provided better temperature control than the304 stainless steel rod (the non-temperature limited heater) in thepresence of varying thermal loads (due to the insulation).

A 6 foot temperature limited heater element was placed in a 6 foot 347Hstainless steel canister. The heater element was connected to thecanister in a series configuration. The heater element and canister wereplaced in an oven. The oven was used to raise the temperature of theheater element and the canister. At varying temperatures, a series ofelectrical currents were passed through the heater element and returnedthrough the canister. The resistance of the heater element and the powerfactor of the heater element were determined from measurements duringpassing of the electrical currents.

FIG. 335 depicts experimentally measured electrical resistance (mΩ)versus temperature (° C.) at several currents for a temperature limitedheater with a copper core, a carbon steel ferromagnetic conductor, and a347H stainless steel support member. The ferromagnetic conductor was alow-carbon steel with a Curie temperature of 770° C. The ferromagneticconductor was sandwiched between the copper core and the 347H supportmember. The copper core had a diameter of 0.5″. The ferromagneticconductor had an outside diameter of 0.765″. The support member had anoutside diameter of 1.05″. The canister was a 3″ Schedule 160 347Hstainless steel canister.

Data 1328 depicts electrical resistance versus temperature for 300 A at60 Hz AC applied current. Data 1330 depicts resistance versustemperature for 400 A at 60 Hz AC applied current. Data 1332 depictsresistance versus temperature for 500 A at 60 Hz AC applied current.Curve 1334 depicts resistance versus temperature for 10 A DC appliedcurrent. The resistance versus temperature data indicates that the ACresistance of the temperature limited heater linearly increased up to atemperature near the Curie temperature of the ferromagnetic conductor.Near the Curie temperature, the AC resistance decreased rapidly untilthe AC resistance equaled the DC resistance above the Curie temperature.The linear dependence of the AC resistance below the Curie temperatureat least partially reflects the linear dependence of the AC resistanceof 347H at these temperatures. Thus, the linear dependence of the ACresistance below the Curie temperature indicates that the majority ofthe current is flowing through the 347H support member at thesetemperatures.

FIG. 336 depicts experimentally measured electrical resistance (mΩ)versus temperature (° C.) data at several currents for a temperaturelimited heater with a copper core, an iron-cobalt ferromagneticconductor, and a 347H stainless steel support member. The iron-cobaltferromagnetic conductor was an iron-cobalt conductor with 6% cobalt byweight and a Curie temperature of 834° C. The ferromagnetic conductorwas sandwiched between the copper core and the 347H support member. Thecopper core had a diameter of 0.465″. The ferromagnetic conductor had anoutside diameter of 0.765″. The support member had an outside diameterof 1.05″. The canister was a 3″ Schedule 160 347H stainless steelcanister.

Data 1336 depicts resistance versus temperature for 100 A at 60 Hz ACapplied current. Data 1338 depicts resistance versus temperature for 400A at 60 Hz AC applied current. Curve 1340 depicts resistance versustemperature for 10 A DC. The AC resistance of this temperature limitedheater turned down at a higher temperature than the previous temperaturelimited heater. This was due to the added cobalt increasing the Curietemperature of the ferromagnetic conductor. The AC resistance wassubstantially the same as the AC resistance of a tube of 347H steelhaving the dimensions of the support member. This indicates that themajority of the current is flowing through the 347H support member atthese temperatures. The resistance curves in FIG. 336 are generally thesame shape as the resistance curves in FIG. 335.

FIG. 337 depicts experimentally measured power factor (y-axis) versustemperature (° C.) at two AC currents for the temperature limited heaterwith the copper core, the iron-cobalt ferromagnetic conductor, and the347H stainless steel support member. Curve 1342 depicts power factorversus temperature for 100 A at 60 Hz AC applied current. Curve 1344depicts power factor versus temperature for 400 A at 60 Hz AC appliedcurrent. The power factor was close to unity (1) except for the regionaround the Curie temperature. In the region around the Curietemperature, the non-linear magnetic properties and a larger portion ofthe current flowing through the ferromagnetic conductor produceinductive effects and distortion in the heater that lowers the powerfactor. FIG. 337 shows that the minimum value of the power factor forthis heater remained above 0.85 at all temperatures in the experiment.Because only portions of the temperature limited heater used to heat asubsurface formation may be at the Curie temperature at any given pointin time and the power factor for these portions does not go below 0.85during use, the power factor for the entire temperature limited heaterwould remain above 0.85 (for example, above 0.9 or above 0.95) duringuse.

From the data in the experiments for the temperature limited heater withthe copper core, the iron-cobalt ferromagnetic conductor, and the 347Hstainless steel support member, the turndown ratio (y-axis) wascalculated as a function of the maximum power (W/m) delivered by thetemperature limited heater. The results of these calculations aredepicted in FIG. 338. The curve in FIG. 338 shows that the turndownratio (y-axis) remains above 2 for heater powers up to approximately2000 W/m. This curve is used to determine the ability of a heater toeffectively provide heat output in a sustainable manner. A temperaturelimited heater with the curve similar to the curve in FIG. 338 would beable to provide sufficient heat output while maintaining temperaturelimiting properties that inhibit the heater from overheating ormalfunctioning.

A theoretical model has been used to predict the experimental results.The theoretical model is based on an analytical solution for the ACresistance of a composite conductor. The composite conductor has a thinlayer of ferromagnetic material, with a relative magnetic permeabilityμ₂/μ₀>>1, sandwiched between two non-ferromagnetic materials, whoserelative magnetic permeabilities, μ₁/μ₀ and μ₃/μ₀, are close to unityand within which skin effects are negligible. An assumption in the modelis that the ferromagnetic material is treated as linear. In addition,the way in which the relative magnetic permeability, μ₂/μ₀, is extractedfrom magnetic data for use in the model is far from rigorous.

Magnetic data was obtained for carbon steel as a ferromagnetic material.B versus H curves, and hence relative permeabilities, were obtained fromthe magnetic data at various temperatures up to 1100° F. and magneticfields up to 200 Oe (oersteds). A correlation was found that fitted thedata well through the maximum permeability and beyond. FIG. 339 depictsexamples of relative magnetic permeability (y-axis) versus magneticfield (Oe) for both the found correlations and raw data for carbonsteel. Data 1346 is raw data for carbon steel at 400° F. Data 1348 israw data for carbon steel at 1000° F. Curve 1350 is the foundcorrelation for carbon steel at 400° F. Curve 1352 is the foundcorrelation for carbon steel at 1000° F.

For the dimensions and materials of the copper/carbon steel/347H heaterelement in the experiments above, theoretical calculations were carriedout to calculate magnetic field at the outer surface of the carbon steelas a function of skin depth. Results of the theoretical calculationswere presented on the same plot as skin depth versus magnetic field fromthe correlations applied to the magnetic data from FIG. 339. Thetheoretical calculations and correlations were made for fourtemperatures (200° F., 500° F., 800° F., and 1100° F.) and five totalroot-mean-square (RMS) currents (100 A, 200 A, 300 A, 400 A, and 500 A).

FIG. 340 shows the resulting plots of skin depth (in) versus magneticfield (Oe) for all four temperatures and 400 A current. Curve 1354 isthe correlation from magnetic data at 200° F. Curve 1356 is thecorrelation from magnetic data at 500° F. Curve 1358 is the correlationfrom magnetic data at 800° F. Curve 1360 is the correlation frommagnetic data at 1100° F. Curve 1362 is the theoretical calculation atthe outer surface of the carbon steel as a function of skin depth at200° F. Curve 1364 is the theoretical calculation at the outer surfaceof the carbon steel as a function of skin depth at 500° F. Curve 1366 isthe theoretical calculation at the outer surface of the carbon steel asa function of skin depth at 800° F. Curve 1368 is the theoreticalcalculation at the outer surface of the carbon steel as a function ofskin depth at 1100° F.

The skin depths obtained from the intersections of the same temperaturecurves in FIG. 340 were input into equations based on theory and the ACresistance per unit length was calculated. The total AC resistance ofthe entire heater, including that of the canister, was subsequentlycalculated. A comparison between the experimental and numerical(calculated) results is shown in FIG. 341 for currents of 300 A(experimental data 1370 and numerical curve 1372), 400 A (experimentaldata 1374 and numerical curve 1376), and 500 A (experimental data 1378and numerical curve 1380). Though the numerical results exhibit asteeper trend than the experimental results, the theoretical modelcaptures the close bunching of the experimental data, and the overallvalues are quite reasonable given the assumptions involved in thetheoretical model. For example, one assumption involved the use of apermeability derived from a quasistatic B-H curve to treat a dynamicsystem.

One feature of the theoretical model describing the flow of alternatingcurrent in the three-part temperature limited heater is that the ACresistance does not fall off monotonically with increasing skin depth.FIG. 342 shows the AC resistance (mΩ) per foot of the heater element asa function of skin depth (in.) at 1100° F. calculated from thetheoretical model. The AC resistance may be maximized by selecting theskin depth that is at the peak of the non-monotonical portion of theresistance versus skin depth profile (for example, at about 0.23″ inFIG. 342).

FIG. 343 shows the power generated per unit length (W/ft) in each heatercomponent (curve 1382 (copper core), curve 1384 (carbon steel), curve1386 (347H outer layer), and curve 1388 (total)) versus skin depth(in.). As expected, the power dissipation in the 347H falls off whilethe power dissipation in the copper core increases as the skin depthincreases. The maximum power dissipation in the carbon steel occurs atthe skin depth of about 0.23 inches and is expected to correspond to theminimum in the power factor, as shown in FIG. 337. The current densityin the carbon steel behaves like a damped wave of wavelength λ=2π

and the effect of this wavelength on the boundary conditions at thecopper/carbon steel and carbon steel/347H interface may be behind thestructure in FIG. 342. For example, the local minimum in AC resistanceis close to the value at which the thickness of the carbon steel layercorresponds to λ/4. Formulae may be developed that describe the shapesof the AC resistance versus temperature profiles of temperature limitedheaters for use in simulating the performance of the heaters in aparticular embodiment. The data in FIGS. 335 and 336 show that theresistances initially rise linearly, then drop off increasingly steeplytowards the DC lines.

FIGS. 344A-C compare the results of the theoretical calculations withexperimental data at 300 A (FIG. 344A), 400 A (FIG. 344B) and 500 A(FIG. 344C). FIG. 344A depicts electrical resistance (mΩ) versustemperature (° F.) at 300 A. Data 1390 is the experimental data at 300A. Curve 1392 is the theoretical calculation at 300 A. Curve 1394 is aplot of resistance versus temperature at 10 A DC. FIG. 344B depictselectrical resistance (mΩ) versus temperature (OF) at 400 A. Data 1396is the experimental data at 400 A. Curve 1398 is the theoreticalcalculation at 400 A. Curve 1400 is a plot of resistance versustemperature at 10 A DC. FIG. 344C depicts electrical resistance (mΩ)versus temperature (° F.) at 500 A. Data 1402 is the experimental dataat 500 A. Curve 1404 is the theoretical calculation at 500 A. Curve 1406is a plot of resistance versus temperature at 10 A DC.

High Voltage Insulated Conductors

Simulations (using STARS) were carried out to simulate heating aformation using the heater embodiments shown in FIGS. 75 and 77. Thesimulation used insulated conductor heaters with Alloy 180 cores withvarious diameters inside jackets with a diameter of 0.625″ and magnesiumoxide insulation between the cores and jackets (for example, core 542,electrical insulator 534, and jacket 540 in FIGS. 75 and 77). Thevarious core diameters used were 0.125″, 0.115″, 0.1084″, and 0.1016″.The various core diameters produced selected amounts of heater power inthe heater (using three insulated conductors in the conduit for theheater). FIG. 345 depicts a plot of heater power (W/ft) versus corediameter (in.). As shown in FIG. 345, core diameters of 0.1016″ providesa heater power of about 220 W/ft; core diameters of 0.1084″ provides aheater power of about 250 W/ft; core diameters of 0.115″ provides aheater power of about 280 W/ft; and core diameters of 0.125″ provides aheater power of about 333 W/ft.

For the simulation, the insulated conductor heaters were placed in aconduit (for example, conduit 570 in FIGS. 75 and 77) with an outsidediameter of 1.75″. The conduit with the insulated conductors was placedin another outside conduit (an outside tubular) that had an outsidediameter of 3.5″ and an inside diameter of 3.094″. The entire heaterassembly was placed in a 6″ wellbore in the formation.

The simulation was used to simulate heating of 2000 feet of formationdepth (target zone) below an overburden of 1225 feet. The voltageprovided to the heaters was a constant voltage of 4160 V. The formationproperties used were for a typical tar sands formation in the PeaceRiver field in Alberta, Canada. The heater spacing was 40 feet.

FIG. 346 depicts power, resistance, and current versus temperature (OF)for a heater with core diameters of 0.105″. Plot 1550 depicts power(W/ft) (left axis) versus temperature. Plot 1552 depicts current (I) inamps (right axis) versus temperature. Plot 1554 depicts resistance (R)in ohms (right axis) versus temperature. As shown in FIG. 346, heaterpower decreased linearly with increasing temperature with resistance andcurrent varying slightly over the temperature range.

FIG. 347 depicts actual heater power (W/ft) versus time (days) duringthe simulation for three different heater designs (three power outputsbased on three core diameters). Plot 1556 depicts power for a heaterwith a designed heater output of 220 W/ft (0.1016″ core diameters). Plot1558 depicts power for a heater with a designed heater output of 250W/ft (0.1084″ core diameters). Plot 1560 depicts power for a heater witha designed heater output of 280 W/ft (0.115″ core diameters). As shownin FIG. 347, the heater power outputs decrease slightly with time butremain relatively constant over the duration of the simulation.

FIG. 348 depicts heater element temperature (core temperature) (° F.)and average formation temperature (° F.) versus time (days) for threedifferent heater designs (three power outputs based on three corediameters). Plot 1562 depicts heater temperature for the heater with thedesigned heater output of 220 W/ft (0.1016″ core diameters). Plot 1564depicts heater temperature for the heater with the designed heateroutput of 250 W/ft (0.1084″ core diameters). Plot 1566 depicts heatertemperature for the heater with the designed heater output of 280 W/ft(0.115″ core diameters). As shown by plots 1566, 1564, and 1562, theheater temperatures increased relatively linearly over time.

Plot 1568 depicts average formation temperature using the heater withthe designed heater output of 220 W/ft (0.1016″ core diameters). Plot1570 depicts average formation temperature using the heater with thedesigned heater output of 250 W/ft (0.1084″ core diameters). Plot 1572depicts average formation temperature using the heater with the designedheater output of 280 W/ft (0.115″ core diameters). Plot 1574 depicts thetarget temperature for the formation of 527° F. As shown by plots 1572,1570, and 1568, the average formation temperatures increased relativelylinearly over time. In addition, time to reach the target formationtemperature decreased with the higher powered heaters. For the 220 W/ftheater, the time to reach the target formation temperature was about1322 days. For the 250 W/ft heater, the time to reach the targetformation temperature was about 1145 days. For the 280 W/ft heater, thetime to reach the target formation temperature was about 1055 days. Thesimulation shows that heater embodiments shown in FIGS. 75 and 77 haverelatively linear heating properties and may be used to heat subsurfaceformations to desired temperatures.

Tubular Induction Heater

Non-linear analysis was used to calculate power versus temperaturecurves at three values of currents for a tubular induction heater. Thetubular was a 6″ Schedule 80 carbon steel tubular. The tubular was usedin heater similar to the heater depicted in FIG. 140. FIG. 349 depictsplots of power versus temperature at the three currents. Plot 1576depicts power versus temperature for a current of 750 A. Plot 1578depicts power versus temperature for a current of 1000 A. Plot 1580depicts power versus temperature for a current of 1250 A. As shown bythe plots in FIG. 349, the turndown ratio for the tubular inductionheater is relatively sharp. The plots also show the effect of current onthe power output for the tubular induction heater.

Insulated Conductor in Conduit with Fluid Between the Conductor and theConduit Simulations

Simulations were performed for a heater including a vertical insulatedconductor in a cylindrical conduit (for example, the heater depicted inFIG. 93) with either air, solar salt, or tin between the insulatedconductor and the conduit. The simulation used a vertical steady state,two dimensional axi-symmetric system with a temperature boundarycondition and a constant power injection rate by the insulated conductorof 300 watts per foot. Values of the temperature boundary condition(temperature of the outside surface of the conduit) were set at 300° C.,500° C. or 700° C. Air was assumed to be an ideal gas. Somerepresentative properties of the solar salt and the tin are given inTable 4. The software used for the simulations was ANSYS CFX 11. Theturbulence model was a shear stress transport model, which is anaccurate model to solve the heat transfer rate in the near wall region.Table 5 shows the heat transfer modes used for each material.

TABLE 4 Molten solar salt Molten tin Density (kg/m³) 1794 6800 Dynamicviscosity (Pa s) 2.10 × 10⁻³ 0.001 Specific heat capacity (J/kg K) 15493180 Thermal conductivity (W/m K) 0.5365 33.5 Thermal expansivity (1/K)2.50 × 10⁻⁴ 2.00 × 10⁻⁴

TABLE 5 Material Heat Transfer Modes Air Radiation, convection, andconduction Solar salt Radiation, convection, and conduction TinConvection and conduction

The simulations were used to examine three different insulated conduitand conduit embodiments. Table 6 shows the sizes of the insulatedconductors and conduits used in the simulations.

TABLE 6 Insulated conductor: Case 1 Case 2 Case 3 core radius (cm): 0.50.25 0.25 insulation thickness (cm) 0.3 0.15 0.15 jacket thickness (cm)0.1 0.05 0.05 Nominal conduit size (inches) 2 2 3.5

FIGS. 350-352 depict temperature profiles for case 1 heaters with theboundary condition temperature set at 500° C. The temperature axis ofthe three figures is different to emphasize the shape of the curves.FIG. 350 depicts temperature versus radial distance for the heater withair between the insulated conductor and the conduit. FIG. 351 depictstemperature versus radial distance for the heater with molten solar saltbetween the insulated conductor and the conduit. FIG. 352 depictstemperature versus radial distance for the heater with molten tinbetween the insulated conductor and the conduit. As shown by the shapeof the curves in FIGS. 350-352, the effect of natural convection for themolten salt is much stronger than the effect of natural convection forair or molten tin. Table 7 shows calculated values of the Prandtl number(Pr), Grashof number (Gr) and Rayleigh number (Ra) for the solar saltand tin when the boundary condition was set at 500° C.

TABLE 7 Material Pr Gr Ra Solar Salt 6.06 4.33 × 10⁵ 2.63 × 10⁶ Tin 0.092.98 × 10⁵ 2.83 × 10⁵

FIG. 353 depicts simulation results for case 1 heaters with the threedifferent materials between the insulated conductors and the conduits,and with boundary conditions of 700° C., 500° C. and 300° C. Region A isthe distance from the center of the insulated conductor to the outsidesurface of the insulated conductor. Region B is the distance from theoutside of the insulated conductor to the inside surface of the conduit.Region C is the distance from the inside surface of the conduit to theoutside surface of the conduit. Curve 1582 depicts the temperatureprofile for air between the insulated conductor and the conduit with theboundary condition for the outer surface of the conduit set at 700° C.Curve 1584 depicts the temperature profile for molten solar salt betweenthe insulated conductor and the conduit with the boundary condition forthe outer surface of the conduit set at 700° C. Curve 1586 depicts thetemperature profile for molten tin between the insulated conductor andthe conduit with the boundary condition for the outer surface of theconduit set at 700° C. Curves 1588, 1590, and 1592 depict thetemperature profiles for air, molten salt, and molten tin respectivelywith the boundary condition for the outer surface of the conduit set at500° C. Curves 1594, 1596, and 1598 depict the temperature profiles forair, molten salt, and molten tin respectively with the boundarycondition for the outer surface of the conduit set at 300° C.

Having air in the gap between the insulated conductor and the conduitresults in the largest temperature difference between the insulatedconductor and the conduit for a given boundary condition temperature,especially for the lower boundary condition of 300° C. For boundarycondition temperatures of 500° C. and 700° C., the temperaturedifference between the insulated conductor and the conduit for themolten salt and air is significantly reduced because of the increase inradiative heat transfer with increasing temperature.

FIG. 354 depicts simulation results for case 2 heaters with the threedifferent materials between the insulated conductors and the conduits,and with boundary conditions of 700° C., 500° C. and 300° C. Region A isthe distance from the center of the insulated conductor to the outsidesurface of the insulated conductor. Region B is the distance from theoutside of the insulated conductor to the inside surface of the conduit.Region C is the distance from the inside surface of the conduit to theoutside surface of the conduit. Curves 1582, 1584, and 1586 depict thetemperature profiles for air, molten salt, and molten tin, respectively,with the boundary condition for the outer surface of the conduit set at700° C. Curves 1588, 1590, and 1592 depict the temperature profiles forair, molten salt, and molten tin, respectively, with the boundarycondition for the outer surface of the conduit set at 500° C. Curves1594, 1596, and 1598 depict the temperature profiles for air, moltensalt, and molten tin, respectively, with the boundary condition for theouter surface of the conduit set at 300° C. As can be seen by comparingFIG. 353 with FIG. 354, decreasing the heater radius results in higherinsulated conductor temperature and therefore larger temperaturedifferences between the insulated conductor and the conduit. As seen inFIG. 353 and in FIG. 354, the temperature profile in the materialbetween the insulated conductor and the conduit falls rapidly for themolten salt and is only slightly higher in temperature than thetemperature profile established when the material is molten metal. Therapid temperature fall for the molten salt may be due to naturalconvection in the molten salt.

FIG. 355 depicts simulation results for case 3 heaters with the threedifferent materials between the insulated conductors and the conduits,and with boundary conditions of 700° C., 500° C. and 300° C. Region A isthe distance from the center of the insulated conductor to the outsidesurface of the insulated conductor. Region B is the distance from theoutside of the insulated conductor to the inside surface of the conduit.Region C is the distance from the inside surface of the conduit to theoutside surface of the conduit. Curves 1582, 1584, and 1586 depict thetemperature profiles for air, molten salt, and molten tin, respectively,with the boundary condition for the outer surface of the conduit set at700° C. Curves 1588, 1590, and 1592 depict the temperature profiles forair, molten salt, and molten tin, respectively, with the boundarycondition for the outer surface of the conduit set at 500° C. Curves1594, 1596, and 1598 depict the temperature profiles for air, moltensalt, and molten tin, respectively, with the boundary condition for theouter surface of the conduit set at 300° C. As can be seen by comparingFIG. 354 with FIG. 355, increasing the size of the conduit results in alower insulated conductor temperature, and a lower and more uniformtemperature in Region B.

FIG. 356 depicts simulation results of temperature (° C.) versus radialdistance (mm) for the three cases examined in the simulation with moltensalt between the insulated conductors and the conduits, and where theboundary condition was set at 500° C. Curve 1600 depicts the results forcase 1, curve 1602 depicts the results for case 2, and curve 1604depicts the results for case 3. The lower insulated conductortemperature (for example, when r=0) for curve 1600 may result from thelarger size of the insulated conductor.

The temperature of insulated conductor (for example, at r=0) is lowerfor curve 1604 than for curve 1602. Also, the temperature of the moltensalt away from the near insulated conductor and near conduit regions islower for curve 1604 than for curves 1600, 1602. The Rayleigh number isproportional to x³, where x is the radial thickness of the fluid. Forthe large conduit (i.e., case 3 and curve 1604), the Rayleigh number isabout 8 times that of the small conduit (i.e., case 2 and curve 1602).The larger Rayleigh number implies that natural convection for the saltin the large conduit is much stronger than the natural convection in thesmaller conduit. The stronger natural convection may increase the heattransfer through the molten salt and reduce the temperature of theinsulated conductor.

Tar Sands Simulation

A STARS simulation was used to simulate heating of a tar sands formationusing the heater well pattern depicted in FIG. 176. The heaters had ahorizontal length in the tar sands formation of 600 m. The heating rateof the heaters was about 750 W/m. Production well 206B, depicted in FIG.176, was used at the production well in the simulation. The bottom holepressure in the horizontal production well was maintained at about 690kPa. The tar sands formation properties were based on Athabasca tarsands. Input properties for the tar sands formation simulation included:initial porosity equals 0.28; initial oil saturation equals 0.8; initialwater saturation equals 0.2; initial gas saturation equals 0.0; initialvertical permeability equals 250 millidarcy; initial horizontalpermeability equals 500 millidarcy; initial K_(v)/K_(h) equals 0.5;hydrocarbon layer thickness equals 28 m; depth of hydrocarbon layerequals 587 m; initial reservoir pressure equals 3771 kPa; distancebetween production well and lower boundary of hydrocarbon layer equals2.5 meter; distance of topmost heaters and overburden equals 9 meter;spacing between heaters equals 9.5 meter; initial hydrocarbon layertemperature equals 18.6° C.; viscosity at initial temperature equals 53Pa·s (53000 cp); and gas to oil ratio (GOR) in the tar equals 50standard cubic feet/standard barrel. The heaters were constant wattageheaters with a highest temperature of 538° C. at the sand face and aheater power of 755 W/m. The heater wells had a diameter of 15.2 cm.

FIG. 357 depicts a temperature profile in the formation after 360 daysusing the STARS simulation. The hottest spots are at or near heaters438. The temperature profile shows that portions of the formationbetween the heaters are warmer than other portions of the formation.These warmer portions create more mobility between the heaters andcreate a flow path for fluids in the formation to drain downwardstowards the production wells.

FIG. 358 depicts an oil saturation profile in the formation after 360days using the STARS simulation. Oil saturation is shown on a scale of0.00 to 1.00 with 1.00 being 100% oil saturation. The oil saturationscale is shown in the sidebar. Oil saturation, at 360 days, is somewhatlower at heaters 438 and production well 206B. FIG. 359 depicts the oilsaturation profile in the formation after 1095 days using the STARSsimulation. Oil saturation decreased overall in the formation with agreater decrease in oil saturation near the heaters and in between theheaters after 1095 days. FIG. 360 depicts the oil saturation profile inthe formation after 1470 days using the STARS simulation. The oilsaturation profile in FIG. 360 shows that the oil is mobilized andflowing towards the lower portions of the formation. FIG. 361 depictsthe oil saturation profile in the formation after 1826 days using theSTARS simulation. The oil saturation is low in a majority of theformation with some higher oil saturation remaining at or near thebottom of the formation in portions below production well 206B. This oilsaturation profile shows that a majority of oil in the formation hasbeen produced from the formation after 1826 days.

FIG. 362 depicts the temperature profile in the formation after 1826days using the STARS simulation. The temperature profile shows arelatively uniform temperature profile in the formation except atheaters 438 and in the extreme (corner) portions of the formation. Thetemperature profile shows that a flow path has been created between theheaters and to production well 206B.

FIG. 363 depicts oil production rate 1606 (bbl/day) (left axis) and gasproduction rate 1608 (ft³/day) (right axis) versus time (years). The oilproduction and gas production plots show that oil is produced at earlystages (0-1.5 years) of production with little gas production. The oilproduced during this time was most likely heavier mobilized oil that isunpyrolyzed. After about 1.5 years, gas production increased sharply asoil production decreased sharply. The gas production rate quicklydecreased at about 2 years. Oil production then slowly increased up to amaximum production around about 3.75 years. Oil production then slowlydecreased as oil in the formation was depleted.

From the STARS simulation, the ratio of energy out (produced oil and gasenergy content) versus energy in (heater input into the formation) wascalculated to be about 12 to 1 after about 5 years. The total recoverypercentage of oil in place was calculated to be about 60% after about 5years. Thus, producing oil from a tar sands formation using anembodiment of the heater and production well pattern depicted in FIG.176 may produce high oil recoveries and high energy out to energy inratios.

Tar Sands Example

A STARS simulation was used in combination with experimental analysis tosimulate an in situ heat treatment process of a tar sands formation.Heating conditions for the experimental analysis were determined fromreservoir simulations. The experimental analysis included heating a cellof tar sands from the formation to a selected temperature and thenreducing the pressure of the cell (blow down) to 100 psig. The processwas repeated for several different selected temperatures. While heatingthe cells, formation and fluid properties of the cells were monitoredwhile producing fluids to maintain the pressure below an optimumpressure of 12 MPa before blow down and while producing fluids afterblow down (although the pressure may have reached higher pressures insome cases, the pressure was quickly adjusted and does not affect theresults of the experiments). FIGS. 364-371 depict results from thesimulation and experiments.

FIG. 364 depicts weight percentage of original bitumen in place (OBIP)(left axis) and volume percentage of OBIP (right axis) versustemperature (° C.). The term “OBIP” refers, in these experiments, to theamount of bitumen that was in the laboratory vessel with 100% being theoriginal amount of bitumen in the laboratory vessel. Plot 1610 depictsbitumen conversion (correlated to weight percentage of OBIP). Plot 1610shows that bitumen conversion began to be significant at about 270° C.and ended at about 340° C. The bitumen conversion was relatively linearover the temperature range.

Plot 1612 depicts barrels of oil equivalent from producing fluids andproduction at blow down (correlated to volume percentage of OBIP). Plot1614 depicts barrels of oil equivalent from producing fluids (correlatedto volume percentage of OBIP). Plot 1616 depicts oil production fromproducing fluids (correlated to volume percentage of OBIP). Plot 1618depicts barrels of oil equivalent from production at blow down(correlated to volume percentage of OBIP). Plot 1620 depicts oilproduction at blow down (correlated to volume percentage of OBIP). Asshown in FIG. 364, the production volume began to significantly increaseas bitumen conversion began at about 270° C. with a significant portionof the oil and barrels of oil equivalent (the production volume) comingfrom producing fluids and only some volume coming from the blow down.

FIG. 365 depicts bitumen conversion percentage (weight percentage of(OBIP)) (left axis) and oil, gas, and coke weight percentage (as aweight percentage of OBIP) (right axis) versus temperature (° C.). Plot1622 depicts bitumen conversion (correlated to weight percentage ofOBIP). Plot 1624 depicts oil production from producing fluids correlatedto weight percentage of OBIP (right axis). Plot 1626 depicts cokeproduction correlated to weight percentage of OBIP (right axis). Plot1628 depicts gas production from producing fluids correlated to weightpercentage of OBIP (right axis). Plot 1630 depicts oil production fromblow down production correlated to weight percentage of OBIP (rightaxis). Plot 1632 depicts gas production from blow down productioncorrelated to weight percentage of OBIP (right axis). FIG. 365 showsthat coke production begins to increase at about 280° C. and maximizesaround 340° C. FIG. 365 also shows that the majority of oil and gasproduction is from produced fluids with only a small fraction from blowdown production.

FIG. 366 depicts API gravity (°) (left axis) of produced fluids, blowdown production, and oil left in place along with pressure (psig) (rightaxis) versus temperature (° C.). Plot 1634 depicts API gravity ofproduced fluids versus temperature. Plot 1636 depicts API gravity offluids produced at blow down versus temperature. Plot 1638 depictspressure versus temperature. Plot 1640 depicts API gravity of oil(bitumen) in the formation versus temperature. FIG. 366 shows that theAPI gravity of the oil in the formation remains relatively constant atabout 100 API and that the API gravity of produced fluids and fluidsproduced at blow down increases slightly at blow down.

FIGS. 367A-D depict gas-to-oil ratios (GOR) in thousand cubic feet perbarrel (Mcf/bbl) (y-axis) versus temperature (° C.) (x-axis) fordifferent types of gas at a low temperature blow down (about 277° C.)and a high temperature blow down (at about 290° C.). FIG. 367A depictsthe GOR versus temperature for carbon dioxide (CO₂). Plot 1642 depictsthe GOR for the low temperature blow down. Plot 1644 depicts the GOR forthe high temperature blow down. FIG. 367B depicts the GOR versustemperature for hydrocarbons. FIG. 367C depicts the GOR for hydrogensulfide (H₂S). FIG. 367D depicts the GOR for hydrogen (H₂). In FIGS.367B-D, the GORs were approximately the same for both the lowtemperature and high temperature blow downs. The GORs for CO₂ (shown inFIGS. 367A-d) was different for the high temperature blow down and thelow temperature blow down. The reason for the difference in the GORs forCO₂ may be that CO₂ was produced early (at low temperatures) by thehydrous decomposition of dolomite and other carbonate minerals andclays. At these low temperatures, there was hardly any produced oil sothe GOR is very high because the denominator in the ratio is practicallyzero. The other gases (hydrocarbons, H₂S, and H₂) were producedconcurrently with the oil either because they were all generated by theupgrading of bitumen (for example, hydrocarbons, H₂, and oil) or becausethey were generated by the decomposition of minerals (such as pyrite) inthe same temperature range as that of bitumen upgrading. Thus, when theGOR was calculated, the denominator (oil) was non zero for hydrocarbons,H₂S, and H₂.

FIG. 368 depicts coke yield (weight percentage) (y-axis) versustemperature (° C./) (x-axis). Plot 1646 depicts bitumen and kerogen cokeas a weight percent of original mass in the formation. Plot 1648 depictsbitumen coke as a weight percent of original bitumen in place (OBIP) inthe formation. FIG. 368 shows that kerogen coke is already present at atemperature of about 260° C. (the lowest temperature cell experiment)while bitumen coke begins to form at about 280° C. and maximizes atabout 340° C.

FIGS. 369A-D depict assessed hydrocarbon isomer shifts in fluidsproduced from the experimental cells as a function of temperature andbitumen conversion. Bitumen conversion and temperature increase fromleft to right in the plots in FIGS. 369A-D with the minimum bitumenconversion being 10%, the maximum bitumen conversion being 100%, theminimum temperature being 277° C., and the maximum temperature being350° C. The arrows in FIGS. 369A-D show the direction of increasingbitumen conversion and temperature.

FIG. 369A depicts the hydrocarbon isomer shift of n-butane-δ¹³C₄percentage (y-axis) versus propane-δ¹³C₃ percentage (x-axis). FIG. 369Bdepicts the hydrocarbon isomer shift of n-pentane-δ¹³C₅ percentage(y-axis) versus propane-δ¹³C₃ percentage (x-axis). FIG. 369C depicts thehydrocarbon isomer shift of n-pentane-δ¹³C₅ percentage (y-axis) versusn-butane-δ¹³C₄ percentage (x-axis). FIG. 369D depicts the hydrocarbonisomer shift of i-pentane-δ¹³C₅ percentage (y-axis) versusi-butane-δ¹³C₄ percentage (x-axis). FIGS. 369A-D show that there is arelatively linear relationship between the hydrocarbon isomer shifts andboth temperature and bitumen conversion. The relatively linearrelationship may be used to assess formation temperature and/or bitumenconversion by monitoring the hydrocarbon isomer shifts in fluidsproduced from the formation.

FIG. 370 depicts weight percentage (Wt %) (y-axis) of saturates fromSARA analysis of the produced fluids versus temperature (° C.) (x-axis).The logarithmic relationship between the weight percentage of saturatesand temperature may be used to assess formation temperature bymonitoring the weight percentage of saturates in fluids produced fromthe formation.

FIG. 371 depicts weight percentage (Wt %) (y-axis) of n-C₇ of theproduced fluids versus temperature (° C.) (x-axis). The linearrelationship between the weight percentage of n-C₇ and temperature maybe used to assess formation temperature by monitoring the weightpercentage of n-C₇ in fluids produced from the formation.

Pre-Heating Using Heaters for Injectivity Before Steam Drive Example

An example uses the embodiment depicted in FIGS. 180 and 181 to preheat.Injection wells 788 and production wells 206 are substantially verticalwells. Heaters 438 are long substantially horizontal heaters positionedso that the heaters pass in the vicinity of injection wells 788. Heaters438 intersect the vertical well patterns slightly displaced from thevertical wells.

The following conditions were assumed for purposes of this example:

(a) heater well spacing; s=330 ft;

(b) formation thickness; h=100 ft;

(c) formation heat capacity; ρc=35 BTU/cu. ft.-° F.

(d) formation thermal conductivity; λ=1.2 BTU/ft-hr-° F.;

(e) electric heating rate; q_(h)=200 watts/ft;

(f) steam injection rate; q_(s)=500 bbls/day;

(g) enthalpy of steam; h_(s)=1000 BTU/lb;

(h) time of heating; t=1 year;

(i) total electric heat injection; Q_(E)=BTU/pattern/year;

(j) radius of electric heat; r=ft; and

(k) total steam heat injected; Q_(s)=BTU/pattern/year.

Electric heating for one well pattern for one year is given by:Q _(E) =q _(h) ·t·s (BTU/pattern/year);  (EQN. 18)with Q_(E)=(200 watts/ft)[0.001 kw/watt](1 yr)[365 day/yr][24hr/day][3413 BTU/kw·hr](330 ft)=1.9733×10⁹ BTU/pattern/year.

Steam heating for one well pattern for one year is given by:Q _(s) =q _(s) ·t·h _(s) (BTU/pattern/year);  (EQN. 19)with Q_(s)=(500 bbls/day)(1 yr) [365 day/yr][1000 BTU/lb][350lbs/bbl]=63.875×10⁹ BTU/pattern/year.

Thus, electric heat divided by total heat is given by:Q _(E)/(Q _(E) +Q _(s))×100=3% of the total heat.  (EQN. 20)

Thus, the electrical energy is only a small fraction of the total heatinjected into the formation.

The actual temperature of the region around a heater is described by anexponential integral function. The integrated form of the exponentialintegral function shows that about half the energy injected is nearlyequal to about half of the injection well temperature. The temperaturerequired to reduce viscosity of the heavy oil is assumed to be 500° F.The volume heated to 500° F. by an electric heater in one year is givenby:V_(E)=πr².  (EQN. 21)

The heat balance is given by:Q _(E)=(πr _(E) ²)(s)(ρc)(ΔT).  (EQN. 22)Thus, r_(E) can be solved for and is found to be 10.4 ft. For anelectric heater operated at 1000° F., the diameter of a cylinder heatedto half that temperature for one year would be about 23 ft. Depending onthe permeability profile in the injection wells, additional horizontalwells may be stacked above the one at the bottom of the formation and/orperiods of electric heating may be extended. For a ten year heatingperiod, the diameter of the region heated above 500° F. would be about60 ft.

If all the steam were injected uniformly into the steam injectors overthe 100 ft. interval for a period of one year, the equivalent volume offormation that could be heated to 500° F. would be give by:Q _(s)=(πr _(s) ²)(s)(ρc)(ΔT).  (EQN. 23)

Solving for r_(s) gives an r_(s) of 107 ft. This amount of heat would besufficient to heat about ¾ of the pattern to 500° F.

Tar Sands Oil Recovery Example

A STARS simulation was used in combination with experimental analysis tosimulate an in situ heat treatment process of a tar sands formation. Theexperiments and simulations were used to determine oil recovery(measured by volume percentage (vol %) of oil in place (bitumen inplace)) versus API gravity of the produced fluid as affected by pressurein the formation. The experiments and simulations also were used todetermine recovery efficiency (percentage of oil (bitumen) recovered)versus temperature at different pressures.

FIG. 372 depicts oil recovery (volume percentage bitumen in place (vol %BIP)) versus API gravity (°) as determined by the pressure (MPa) in theformation. As shown in FIG. 372, oil recovery decreases with increasingAPI gravity and increasing pressure up to a certain pressure (about 2.9MPa in this experiment). Above that pressure, oil recovery and APIgravity decrease with increasing pressure (up to about 10 MPa in theexperiment). Thus, it may be advantageous to control the pressure in theformation below a selected value to get higher oil recovery along with adesired API gravity in the produced fluid.

FIG. 373 depicts recovery efficiency (%) versus temperature (° C.) atdifferent pressures. Curve 1650 depicts recovery efficiency versustemperature at 0 MPa. Curve 1652 depicts recovery efficiency versustemperature at 0.7 MPa. Curve 1654 depicts recovery efficiency versustemperature at 5 MPa. Curve 1656 depicts recovery efficiency versustemperature at 10 MPa. As shown by these curves, increasing the pressurereduces the recovery efficiency in the formation at pyrolysistemperatures (temperatures above about 300° C. in the experiment). Theeffect of pressure may be reduced by reducing the pressure in theformation at higher temperatures, as shown by curve 1658. Curve 1658depicts recovery efficiency versus temperature with the pressure being 5MPa up until about 380° C., when the pressure is reduced to 0.7 MPa. Asshown by curve 1658, the recovery efficiency can be increased byreducing the pressure even at higher temperatures. The effect of higherpressures on the recovery efficiency is reduced when the pressure isreduced before hydrocarbons (oil) in the formation have been convertedto coke.

Molten Salt Circulation System Simulation

A simulation was run using molten salt in a circulation system to heatan oil shale formation. The well spacing was 30 ft, and the treatmentarea was 5000 ft of formation surrounding a substantially horizontalportion of the piping. The overburden had a thickness of 984 ft. Thepiping in the formation includes an inner conduit positioned in an outerconduit. Adjacent to the treatment area, the outer conduit is a 4″schedule 80 pipe, and the molten salt flows through the annular regionbetween the outer conduit and the inner conduit. Through the overburdenof the formation, the molten salt flows through the inner conduit. Afirst fluid switcher in the piping changes the flow from the innerconduit to the annular region before the treatment area, and a secondfluid switcher in the piping changes the flow from the annular region tothe inner conduit after the treatment area.

FIG. 374 depicts time to reach a target reservoir temperature of 340° C.for different mass flow rates or different inlet temperatures. Curve2028 depicts the case for an inlet molten salt temperature of 550° C.and a mass flow rate of 6 kg/s. The time to reach the target temperaturewas 1405 days. Curve 2030 depicts the case for an inlet molten salttemperature of 550° C. and a mass flow rate of 12 kg/s. The time toreach the target temperature was 1185 days. Curve 2032 depicts the casefor an inlet molten salt temperature of 700° C. and a mass flow rate of12 kg/s. The time to reach the target temperature was 745 days.

FIG. 375 depicts molten salt temperature at the end of the treatmentarea and power injection rate versus time for the cases where the inletmolten salt temperature was 550° C. Curve 2034 depicts molten salttemperature at the end of the treatment area for the case when the massflow rate was 6 kg/s. Curve 2036 depicts molten salt temperature at theend of the treatment area for the case when the mass flow rate was 12kg/s. Curve 2038 depicts power injection rate into the formation (W/ft)for the case when the mass flow rate was 6 kg/s. Curve 2040 depictspower injection rate into the formation (W/ft) for the case when themass flow rate was 12 kg/s. The circled data points indicate whenheating was stopped.

FIG. 376 and FIG. 377 depicts simulation results for 8000 ft heatingportions of heaters positioned in the Grossmont formation of Canada fortwo different mass flow rates. FIG. 376 depicts results for a mass flowrate of 18 kg/s. Curve 2042 depicts heater inlet temperature of about540° C. Curve 2044 depicts heater outlet temperature. Curve 2046 depictsheated volume average temperature. Curve 2048 depicts power injectionrate into the formation. FIG. 377 depicts results for a mass flow rateof 12 kg/s. Curve 2042 depicts heater inlet temperature of about 540° C.Curve 2050 depicts heater outlet temperature. Curve 2052 depicts heatedvolume average temperature. Curve 2054 depicts power injection rate intothe formation.

In this patent, certain U.S. patents, U.S. patent applications, andother materials (for example, articles) have been incorporated byreference. The text of such U.S. patents, U.S. patent applications, andother materials is, however, only incorporated by reference to theextent that no conflict exists between such text and the otherstatements and drawings set forth herein. In the event of such conflict,then any such conflicting text in such incorporated by reference U.S.patents, U.S. patent applications, and other materials is specificallynot incorporated by reference in this patent.

Further modifications and alternative embodiments of various aspects ofthe invention may be apparent to those skilled in the art in view ofthis description. Accordingly, this description is to be construed asillustrative only and is for the purpose of teaching those skilled inthe art the general manner of carrying out the invention. It is to beunderstood that the forms of the invention shown and described hereinare to be taken as the presently preferred embodiments. Elements andmaterials may be substituted for those illustrated and described herein,parts and processes may be reversed, and certain features of theinvention may be utilized independently, all as would be apparent to oneskilled in the art after having the benefit of this description of theinvention. Changes may be made in the elements described herein withoutdeparting from the spirit and scope of the invention as described in thefollowing claims. In addition, it is to be understood that featuresdescribed herein independently may, in certain embodiments, be combined.

1. A method for forming two or more wellbores in a subsurface formation,comprising: forming a first wellbore in the formation; directionallydrilling a second wellbore in a selected relationship relative to thefirst wellbore; transmitting a first electromagnetic wave from a firsttransceiver in the first wellbore and sensing the first electromagneticwave using a second transceiver in the second wellbore; transmitting asecond electromagnetic wave from the second transceiver in the secondwellbore and sensing the second electromagnetic wave using the firsttransceiver in the first wellbore; continuously assessing a position ofthe second wellbore relative to the first wellbore using the sensedfirst electromagnetic wave and the sensed second electromagnetic wave;and adjusting the direction of drilling of the second wellbore so thatthe second wellbore remains in the selected relationship relative to thefirst wellbore.
 2. The method of claim 1, further comprising assessingnatural electromagnetic fields using a third transceiver positioned at adistal end of the first wellbore.
 3. The method of claim 1, wherein thefirst transceiver is coupled to a surface of the formation.
 4. Themethod of claim 1, wherein the first transceiver is directly coupled toa surface of the formation via a wire.
 5. A method for forming two ormore wellbores in a subsurface formation, comprising: forming aplurality of first wellbores in the formation; providing a plurality ofelectromagnetic waves in the first wellbores; directionally drilling oneor more second wellbores in a selected relationship relative to thefirst wellbores; continuously sensing the electromagnetic waves in thefirst wellbores using at least one electromagnetic antenna in the secondwellbores, wherein the antenna is located in a heater that is to be usedto provide heat in at least one of the second wellbores; continuouslyassessing a position of the second wellbores relative to the firstwellbores using the sensed electromagnetic waves; and adjusting thedirection of drilling of at least one of the second wellbores so thatthe second wellbore remains in the selected relationship relative to thefirst wellbores.
 6. The method of claim 5, wherein at least one of thesecond wellbores is formed substantially perpendicular to at least oneof the first wellbores.
 7. The method of claim 5, further comprisingproviding the electromagnetic waves using electromagnetic sondes.
 8. Themethod of claim 5, further comprising continuously adjusting thedirection of drilling of at least one of the second wellbores using thecontinuously assessed position of the at least one of the secondwellbores relative to the first wellbores.
 9. A method for forming twoor more wellbores in a subsurface formation, comprising: forming a firstwellbore in the formation; assessing a position of the first wellbore;drilling a second wellbore in a selected relationship relative to thefirst wellbore; continuously assessing a position of the second wellborerelative to the first wellbore; adjusting the direction of drilling ofthe second wellbore so that the second wellbore remains in the selectedrelationship relative to the first wellbore; drilling one or moreadditional wellbores in a selected relationship to the second wellbore;continuously assessing a position of at least one of the additionalwellbores relative to the first wellbore and/or the second wellbore; andadjusting the direction of drilling of the at least one of theadditional wellbores so that the at least one of the additionalwellbores remains in the selected relationship relative to the secondwellbore.
 10. The method of claim 9, wherein the second wellbore isformed substantially perpendicular to the first wellbore.
 11. The methodof claim 9, wherein at least one of the additional wellbores is formedsubstantially parallel to the second wellbore.
 12. The method of claim9, wherein continuously assessing the position of the second wellborerelative to the first wellbore, comprises: transmitting a firstelectromagnetic wave from a first transceiver in the first wellbore andsensing the first electromagnetic wave using a second transceiver in thesecond wellbore; transmitting a second electromagnetic wave from thesecond transceiver in the second wellbore and sensing the secondelectromagnetic wave using the first transceiver in the first wellbore;and continuously assessing the position of the second wellbore relativeto the first wellbore using the sensed first electromagnetic wave andthe sensed second electromagnetic wave.
 13. The method of claim 9,wherein continuously assessing the position of the at least one of theadditional wellbores relative to the second wellbore, comprises:transmitting a first electromagnetic wave from a first transceiver inthe first wellbore and/or the second wellbore and sensing the firstelectromagnetic wave using a second transceiver in the at least one ofthe additional wellbores; transmitting a second electromagnetic wavefrom the second transceiver in the at least one of the additionalwellbores and sensing the second electromagnetic wave using the firsttransceiver in the first wellbore and/or the second wellbore; andcontinuously assessing the position of the at least one of theadditional wellbores relative to the second wellbore using the sensedfirst electromagnetic wave and the sensed second electromagnetic wave.14. The method of claim 9, wherein continuously assessing the positionof the second wellbore relative to the first wellbore, comprises:providing a current path and voltage signal to the first wellbore;continuously sensing the voltage signal in the second wellbore; andcontinuously assessing the position of the second wellbore relative tothe first wellbore using the sensed voltage signal.
 15. The method ofclaim 9, wherein continuously assessing the position of the at least oneof the additional wellbores relative to the second wellbore, comprises:providing a current path and voltage signal to the first wellbore and/orthe second wellbore; continuously sensing the voltage signal in the atleast one of the additional wellbores; and continuously assessing theposition of the at least one of the additional wellbores relative to thesecond wellbore using the sensed voltage signal.
 16. The method of claim9, further comprising assessing a position of the first wellborerelative to at least one of the additional wellbores in the formation toverify the position of the first wellbore.
 17. The method of claim 9,further comprising assessing a position of the second wellbore relativeto at least one of the additional wellbores in the formation to verifythe position of the second wellbore.
 18. A method for forming two ormore wellbores in a subsurface formation, comprising: forming aplurality of first wellbores in the formation; providing a plurality ofelectromagnetic waves in the first wellbores; directionally drilling oneor more second wellbores in a selected relationship relative to thefirst wellbores, wherein at least one of the second wellbores is formedsubstantially perpendicular to at least one of the first wellbores;continuously sensing the electromagnetic waves in the first wellboresusing at least one electromagnetic antenna in the second wellbores;continuously assessing a position of the second wellbores relative tothe first wellbores using the sensed electromagnetic waves; andadjusting the direction of drilling of at least one of the secondwellbores so that the second wellbore remains in the selectedrelationship relative to the first wellbores.
 19. The method of claim18, further comprising providing the electromagnetic waves usingelectromagnetic sondes.
 20. The method of claim 18, further comprisingcontinuously adjusting the direction of drilling of at least one of thesecond wellbores using the continuously assessed position of the atleast one of the second wellbores relative to the first wellbores.